ML20153F628
| ML20153F628 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 01/08/1988 |
| From: | Landon J UTAH POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML20153F598 | List: |
| References | |
| NUDOCS 8805110008 | |
| Download: ML20153F628 (50) | |
Text
r
?s '
s g
Exhibit B UNITED STATES OF AMERICA BEFORE THE NUCLEAR REGULATORY COMMISSION 5-IN THE MATTER OF THE
)
EXHIBIT B to Facility APPLICATION OF PACIFICORP
)
Operating License No. NPF-1 o
FOR CONSENT TO THE TRANSFER )
Indemnity Agreement No. B-78 OF LICENSES
)
3 PREFILED TESTIMONY OF JOHN H.
LANDON t
E805110008 G80509 PDR ADOCK 0500 4
T
e EXHIBIT NO. 14
-,e f
UNITED STATES OFsAMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Utah Power & Light Company
)
PacifiCorp
)
Docket No. EC88-2-000 PC/UP&L Merging Corp.
)
PREFILED TESTIMONY OF JOHN H. LANDON ON BEHALF OF UTAH POWER & LIGHT COMPANY PACIFICORP PC/UP&L MERGING CORP.
i January 8, 1988 i
i r
7
-,e
m
, - -,-,,,.,a w
n,~-----
- g bE s
SUMMARY
OF TESTIMONY OF JOHN H. LANDON ISSUES ADDRESSED The relevant product markets for which the merger's effect 1.
on competition should be considered.
The effect on bulk power competition in the following 2.
geographic markets:
The California-Southern Nevada Area A.
The Arizona-New Mexico Power Area B.
The Northwest Power Pool Area C.
The Rocky Mountain Power Area D.
the bulk power could materially affect 3.
Factors that analysis.
Effect of the merger on the retail market.
4.
Effect of the merger on the coal market.
5.
The Department of Justice Merger Guidelines and other 6.
to the merger.
considerations relevant Overall effect of the merger on competition.
7.
e'.
.t CONTENT AND CONCLUSIONS Relevant Product Market A product market is identified primarily by assessing the realistic "substitutability" among products as viewed by consumers.
The product markets that are relevant to the proposed merger are the markets for bulk power, retail electricity and coal.
While recent past experience in these markets is relevant, it is future markets and conditions chat are most significant.
Effect on Bulk Power Competition in the Relevant Geocraphic Markets The starting point for determining the relevant geographic markets is the Western Systems Coordinating Council (WSCC), a voluntary organization co,nsisting of all major power suppliers and many smaller ones in the Western United States.
The WSCC region is divided into four areas, the Northwest Power Pool Area, the Rocky Mountain Power Area, the Arizona-New Mexico Power Area, and the California-Southern Nevada Power Area.
These areas were determined by the WSCC members on the basis of concentrations of natural resources in the geographical location and population and industry.
Transmission systems within the areas tend to be mere l
integrated than do those between areas.
These areas constitute l
- he relevant geographic markets for bulk power in the Western United States.
L e
i.
5 i \\
The California-Southern Nevada Area Market Sales of bulk power to utilities in the California-Southern Nevada Area (California Area) are, and are projected to continue to be, the largest and most significant net transfer between WSCC areas.
A large number of bulk power suppliers make sales to the California Area, and there are substantial and diverse transmission facilities over which those sales are made.
PP&L and UP&L ranked sixth and twelfth, respectively, in 1986 total sales into the area; the combined companies would have ranked third, but their' total sales would have constituted only slightly over 8% of the total.
Analysis of the market using Herfindahl-Hirschman Indices indicates that the merger vill have a very small effect on concentration in the total California Area bulk power market and no effect on concentration in the market for firm sales of energy.'and capacity, and that these results are well within what is allowed by the Department of Justice Merger Guidelines.
Of the substantial and diverse transmission capacity into the California Area, PP&L owns only-3.3% and UP&L owns none.
PP&L has lass than 8% of the direct north-to-south capability into the California Area.
4 W
e.
.w,
J The Arizona-New Mexico Fov_gg Area Present'ly and for the foresseable future, this area is expected to have enough generation reserves to be self-sufficien't and to be a net exporter into the California Area.
There vill, however, be sales into the area, primarily during outages of base load generation.
These sales make the region a relevant market, although one with greatly reduced significance.
UP&L and PP&L together control only approximately 12.6% of the substantial and diverse transmission capacity into the area and 6.4% of bulk c:
power sales.
The..otchwest Power Pool Area This area is projected to be a net exporter of bulk power through 1996.
PP&L and UP&L are both important utilitie.s within the area, but even combined they have only a small percentage (about 12% in 1987 and 9% projected in 1996) of the generating capab!.lity of the region.
PP&L and UP&L together have 330 megawatts of a total transfer capacity from California of 4,814 megawatts, 896 megawatts of a total transfer capacity from the Rocky Mountain Power Area of 3,692 megavatts, and all of the 600 megavatt transmission capacity, presently owned by UP&L, directly connected with the Arizona-New Mexico Poser Area.
Of the total inter-regional transfer capacity into the Northwest Power Pool Area of 9,106 megawatts, the merged company would own approximately 20%.
, - - -, - -.. -. - - - --+,-
1 4-.
The Rocky Mountain Power Area This area is projected to be a net exporter of bulk power through 1996.
PP&L and UP&L in 1986 together supplied only 2.3%
of the unergy and 2.5% of the power in the area.
Virtually all of the energy and all of the power was from PP&L and would not be affected by the merger.
The amounts are too small to represent a significant impact in the area.
PP&L and UP&L together control 864 megawatts of the total interregional transmission capacity into the area of 4,362 megawatts.
Factors Which Could Materially Affect The Bulk Power Analysis An increase in the relative prices of oil and gas could cause the California Area to have even greater incentives to generate less and import more.
If the level of demand in the Arizona-New Mexico Power Area were to grow faster than forecast, that area vould be loss able to export to the California Area and would be more likely to import from the Northwest Power Pool Area and the Rocky Mountain Power Area.
The Retail Market Some potential for yardstick and industrial location competition exists between UP&L and PP&L at retail.
The prospect of franchise competition between the merging utilities is too er
remote to warrant consideration because the two utilities are adjacent at only a few points and they generally serve exclusive areas designated by state law.
The merger will not materially affect whatever industrial location competition there may be.
If there are industrial concerns that consider location in either the UP&L or PP&L service areas, they are likely also to consider locations served by other Northwest utilities, including adjacent low-cost utilities.
The merger will not significantly reduce competition in this market.
The merger will not materially reduce yardstick competition because the two companies served are so different that the prospect of meaningful yardstick competition is remote.
Many alternative yardsticks are available.
+
The Coal Market The coal market examined is roughly the same geographic area as the WSCC, comprising coal produced in Colorado, Wyoming, Montana, Utah, New Mexico, Arizona and Washington.
This market is presently competitive and would remain so even if the coal operations of UP&L and NERCO (a PP&L affiliate) were combined, and that is not contemplated.
The combined company would control only 6% of uncommitted resources.
a.
s-The merger vill have little or no impact on the Western coal market because the companies plan to keep the'
- oal operations separate, they do not plan to change coal procurement activitits, the companies together would control less than 6% of the controlled, uncommitted coal reserves in the Western ccal market, most of PPf..L's coal-fired power plants are jointly owned with wholesale competitors whc have some influence on coal supply, and there is only one contract under which either of the companies sell to a potential wholesale power competitor.
The merged company will not have the ability to restrict access to the coal market by any wholzsaie power competitors.
Mercer Guidelines and Other Considerations There ar2 capital cost, lead time and regulatory barriers to entr'y into generation and transmission in the relevant geographic markets.
These have, however, proved to be low relative to the resources of area firms.
Entry has been and is expected to be substantial.
The stated post-merger wheeling policy of the companies has a sound basis in economics and does not have any anticompetitive effect.
Nothing about the proposed policy would make access to Qli w$.Th)7 transmission more restricted than it now is, and, in fac,, the
" lSC
. licy would clarify and most likely enhance the access to 7.,
Tj?Yj fE ansmission.
i
{
~
-l
~~
l The merger vill not result in any increased ability or incentive.of the combined utility to profit from UP&L's j
strategically located transmission system.- The fact that UP&L or
]
the merged entity may earn profits on its use of the transmission system does not indicata that there is ar. anticompetitive problem.
It is a natural result of the substantial disparity between costs in the northwestern and southeastern portions of the WSCC region, and it is not inappropriate for UP&L's retail rate payers to realize the benefits.
The combined utility will not be in a position to charge higher prices for Northwest energy than UP&L can do at present l -
because it will have no more control over the available
{
transmission options than UP&L presently has.
i The merger vill not reduce the incentive to produce the t
i
,least expens ve energy to replace the merged company's own energy for sale in the Arizona-New Mexico Power Area because the incentive to minimize costs associated with the market sales vill P
continue.
Overall Effset of Merger on C,c_npe t i t ion l
The proposed merger vill not tend to create a monopoly or leswen competition in any relevant market, nor vill it result in i
a significant increase in concentration of economic power or j
control over facilities essent'ai to participation in the bulk s
4
9_
power mar'tet. Numerous alternative pathways exist from the Pacific Northwest to the Southwestern United States, including California.
Barriers to new entry into the generation and transmission markets are relatively lov and unaffected by the merger.
The merged company vill not control access to coal by its competitors.
Overall, the merger vill have pro-competitive rather than anticompetitive effect.
+
l i
9
,_m
o '.
i nhibit No.14 Page 1 1
UTAH POWER AND LIGHT COMPANY, PACIFICORP 2
PC/UP&L MERGING CORPORATION 3
DOCKET NO. EC33-2-000 4
TESTIMONY OF JOHN H. LANDON 5
6 I. QUALIFICATIONS AND PURPOSE 7
Q. Ficase state youi name and business address.
8 A.
My name is John H. Landon and my business address is 1800 M 9
Street, N.W., Washington, D.C.
10 Q. What is your current position?
11 A.
I am a Senior Vice President of National Economic Research 12 Associates, Inc. (NERA), an economic consulting firm.
13 Q. Please outline your educational background 14 A.
I received a B.A. degree with highest honors from Michigan State 15 University with a major in economics in 1964. I subsequently attended graduate 16 school at Cornell University where I was awarded an M.A. in economics in 196*
17 and a Ph.D. in the same field in 1969.
18 Q. What areas of economics did you specialize in during your graduate 19 program at Cornell University?
20 A.
I specialized in industrir.1 v 3a.czation, consisting of regulatory 21 economics and the study of the strue...e.
conduct and performance of 22 inem: ries. My minct fields were labor and monetary economice.
23 Q. Where were you employed after leaving Cornell University?
24 A.
I served on the faculty of Case Western Reserve University from 1968 I
25 to 1973, rising from the rank of assistant professor to associate professor, and 26 on the faculty of the '? versity of Delaware from 1972 to June 1977 as an n e T n*
I
4 4 4
e' Exhibit No.14
?
Page 2 1
associate professor.
2 Q. What subjects did you teach during this period?
3 A.
I taught microeconomics, industrial organization, antitrust economics, 4
regulatory economics and forecasting.
5 Q. What other positions have you held?
6 A.
I have been a senior research associate in the Research Program in 7
Industrial Economics at Case Western Reserve University, a director of the 8
Lelaware Econometric Model Group, the director of the Center for Policy 9
Studies at the University of Delaware and a member of the Governor of 10 Delaware's Economic Advisory Committee.
Il Q. Have you authored or coauthored any published articles?
12 A.
Yes.
I hase authored or coauthored approximately 20 published 13 articles and chapters in books.
The articles have appeared in such journals as 14 The Amerienn Economic Review, Southern Economic Journal. The Antitrust 15 Bulletin. Industrial and Labor Relations Review and Enernv Law Journal.
16 Q. What subjects have these articles and chapters dealt with?
17 A.
They all deal with one aspect or another of the interrelationships i
18 among industry structure, behavior and performance.
This has been the focus 19 of my graduate study, teaching and research.
The industries covered in:lude 20
' newspaper, construction, electric utility, education, oil and medical care.
l l
21 Q. How many of your published articles and book chapters deal with the l
l 22 economics of the electric utility industry?
f 23 A.
Seven pub!bhed articles and two book chapters deal with economie 24 analysis of electric utilities.
In particular, they all concentrate on the relation-25 ship between the structure of the industry and its economic performance.
26 Q. Are you a member of any professional associations?
n e ra'
._ _ ~ _. _
!.i g, _
Exhibit %.14 Page 3 7
.1 A.
I am a member of the American Economic Association.
2
. Q. Have you delivered any papers at meetings of professional organiza-3 tions?
4 A.
Yes.
I have delivered papers at meetings of the ' institute of Manage-5 ment Science, th II.1ustrial Relations Research Association, the Midwestern 6
Economic Association, the Western Economic Association and the Eccnometric 7
Society.
My papers concerning the electric utility industry have, on two 8
occasions, been selected for presentation at the American Telephone and 9
Telegraph Seminar on Regulation and Public Utilities at Dartmouth College.
t 10 Q. How long have you been employed by NERA7 11 A.
I have been employed by NERA since February 1977 on a part-time 12 basis and have been with the firm on a full-time basis since June 1977.
13 Q. What has been the nature of your assignments since joining NF.RA7 14 A.
Since joining NERA, I have worked primarily on issues relating to the 15 application of economic principles to the electric utility industry.. I have 16' participated in several projects addressing economic and related antitrust issues 17 in connection with proceedings before the Federal Energy Regulatory Commis-18 sion (FERC), the Nuclear Regulatory Commission (NRC), the Securities and 19 Exchange Commission (SEC), state regulatory commissions and federal district 20 courts.
21 Q. Have you testified previously?
I j
22 A.
Yes.
I have testified on numerous occasions before federal district l
23 courts and various state and federal regulatory agencies on a variety of utility 24 matters. A list of these testimonies appears as Schedule I to Exhibit No.15.
1 25 Q. Did you prepare, or have prepared under your supervision and i
26 control, the testimony that is included as Exhibit 14 and the 43 schedules which neTa'
..,,_--n
.___,r
...._..,_m.
_,,m.-_7_--c_.--..-.-~n
e.
Exhibit No.14 Page 4 1
are included as Exhibit 15 for this proceeding?
2 A.
Yes.
3 Q. What is the purpose of your testimony?
4 A.
I have been asked to assess the proposed merger between Pacific 5
Power knd I.ight Company (PP&L) and Utah Power and Light Company (UP&L) 6 and draw a cont.usion as to the effect of the merger on competition.
7 I1., STATEMENT OF CONCLUSIONS 8
Q. What conclusion have you drawn regarding the effect of the merger 9
on competition?
10 A.
The proposed merger will not have an adverse effect on competition 11 in any markets in which PP&L and UP&L compete.
12 Q. On what do you base your conclusion?
13 A.
This conclusion is based on an analysis of actual and potential 14 competition in the markets potentially affected ty a merger between PP&L and 15 UP&L. The primary findings of this analysis are:
16 1.
I have identified six markets in which the merging firrta have 17 historically been substantial participants.
These are:
(1) The market fw retail 18 sales in the areas within and adjacent to the service areas of the merging 19 firms; (2) the market for bulk power sales into the California-Southern Nevada 20 Power Area (California Area); (3) the market for bulk power sales into the 21 Ari-on-New Mexico Power Area; (4) the market for bulk power sales inte the 22 Rocky Mountain Power Area; (5) The internal Northwest bulk power market; and 23 (6) the market for coal in the Northwest.
For each of these markets, I have l
24 assessed:
(1) the degree of concentration both before and after the merger as 25 measured by conentration ratios and/or by Herfindahl-Hirschman Indicies 26 (HHis); (2) the barriers to entry into these markets; (3) the actual and potential n e T a'
s.
Exhibit No.14
.9 Page 5 I
significance of each market; and (4) the degree to which the merged entity can 2
control the price or quantity of sales into or from these markets.
On the basis 3
of this assessment, I have concluded that, while the n:erging entities are large 4
firms, they are not particularly large in the context of the markets in which 5
they compete.
Their combination will not tend to create monopoly power or 6
lessen competition.
7 2.
As a general matter, there is no direct retail competition between 8
the merging companies.
For the most part, their systems are not directly 9
adjacent to each other.
In the markets in which they may compete with each 10 other, there are many other rivals.
The merger actually can be expected to 11 enhance competition as the projected economies are realized.
This may result 12 in lost sales for some ' competitors, but will enhance the competitive proces'.
13 The merger will not create or enhance artificial barriers to other retail 14 competitors.
15 3.
The present and forecast relationships between loads and 16 generating reMurces in the California Area make it likely that this will be a 17
!arge and growing market for capacity and energy purchased from suppliers l
18 outside the area.
The suppliers to the California Area include all substantial i
l 19 Northwest generating entities as well as those in the Rocky Mountain Power 20 Area and the Arizona-New Mexico Power Area.
The merging firms together 21 mrke a relatively small share of the sales into this market and control a 22 comparably small proportion of the transmission access to the California.narket.
23 Substantial additional transmission facilities are planned by other entities.
24 4.
The Arizona-New Mexico Power Area, while historically a sub-l l
25 stantial net importer of power and energy, now has a substantial level of 26 reserves and is supplied principally by relatively low-fuel-cost nuclear and coal ne rtT l
Exhibit No.14 Page 6 1
facilities within the area.
This region is likely to be a significant net exporter 2
of power and energy over the oext several years.
This area has substantial 3
transmission ties with the California, Rocky Mountain and Northwest areas.
4 The proposed merger would not materially affect the marht for the supply'of 5
bulk power to this region.
6 5.
Except for the Bonneville Power Administration (BPA), sales 7
among major generating utilities in the Northwest do not account for a major 8
proportion of bulk power supplies.
While there is a modest bulk power market 9
among Northwest utilities, the merging parties have a relatively small share.
10 Moreover, during the period of the year in which Northwest entities are likely 11 to be significant purchasers, there is adequate transmission capacity to import 12 energy and capacity into the region.
13 6.
The Rocky Mountain Power Area is generally self-sufficient and 14 is not a substantial purchaser from either of the merging parties.
The utilities
[
15 in this area may be potential competitors for sales into the California Area.
16 7.
Entry into both the transmission and generation portions of the 17 bulk power markets is easy in the long term. The large number of transmission 18 lines, either under construction or in the planning process, indicates strongly 19 that lines are built when there is a long-term advantage.
The large amount of 20 capacity added in these areas in recent years, together with the large number 21 of participating utilities, also inditates that bulk power supply will continue to 22 be highly competitive.
Cogeneration and independent power producers are a 23 significant competitive presence in CalifornL, which is the most significant bulk 24 power market in which the merging firms compete.
25 8.
There will be little or no impact on western coal markets from i
26 the merser, n e Ta'
Exhibit No.18 Page 7 1
III. DEFINING RELEVANT MARKETS 2
Q. Please describe how you determine relevant markets within which to 3
evaluate the effect of a proposed merger on competition.
4 A.
First, it is necessary to define the relevant market or markets in 5
terms of the product and geographic limits (if any).
It is also necessary to 6
establish the proper time frame for assessing competition in defining relevant 7
market or markets.
Once the market is defined and the proper time frame 8
established, the degree of competition in each market can be assessed.
In 9
.particular, the relevant markets should be assessed in terms of:
(1) the number 10 and relative size of buyers and sellers (including the calculation of HHis or 11 other appropriate measures); (2) the volume and frequency of tansactiers that 12 occur in the market; (3) the cost and availability of alternatives (including 13 other fuels); Lnd (4) the ease with which new participants may enter the market 14 (including relevant institutional or contractual arrangements).
These structural 15 elements of the tr.arket. will cetermine the degree of existing and prospective 16 competition and whether a proposed change (i.e., merger) is likely to have a 17 negative or positive effect on competition in that market.
18 Q. Please describe how you go about defining a market.
19 A.
In broad terms, a market is properly viewed as an arena within which 20 buyers and sellers engage in the exchange of a good or service.
To define a 21 particular market, it is necessary to establish its specific product and geo-22 graphic dimensions.
As I indicated above, time is also an important dimension 23 of markets, especially in dynamic industries where changes in technology, 24 regulation, legal constraints and relative costs occur rapidly.
25 Q. How is the product identified?
26 A.
A product market is identified primarily by assessing the realistic n e I'n'
Erhlblt No.14 Page g 1
' substitutability' among products as viewed by consumers.
In defining' markets, 2
the concern is not with products that ss,uld be substituted fer one another or 3
those that are possible substitutes, but with commercially realistic substitutes.
4 Product markets should be defined broadly enough.to include all goods and 5
services that consumers view as realistically interchangeable or substitutable for 6
each other.
The definition, however, should be narrow enough to exclude goods 7
and services which consumers do not consider m2aningful substitutes and to 8
include institutional limitations.
9 Supply substitutability should also be considered.
Supply substitut-10 ability refers to the ability of firms to shift the personnel and equipment used 11 in supplying one good into the furnishing of a second.
When suppliers can 12 effectively produce, distribute and market a product in the short run (i.e.,
13 without substantial modification of production facilities),
they should be 14 included in the market even if they do not presently produce the product in 15 question.
16 Q. How do you identify the appropriate geographic market?
17 A.
The geographic extent of a market is defined to include the area to 18 which consumers can realistically turn for alternatives.
Transportation costs, 19 along with the magnitude of the savings that may be available by shopping a 20 broader area, will typically demarcate a geographic region over which shopping i
21 is realistic.
As with product market boundaries, geographic market boundaries 22 may be importantly influenced by lastitutional limitations on substitutability.
23 Q. How do you identify the appropriate time dimension of.t market?
l l
24 A.
When alternatives differ significantly over time, different markets j
25 should be defined.
Changes may occur in the nature of the product or its 26 substitutes, in transportation costs, in the deEree of supply substitutability, or n e ra' P
J.
s Erhlbit No.14 I
Page 9 1
in the legal and lastitutional factors which are used to define commercially 2
realistic alternatives.
For example, over a longer term, new entry and' new 3
alternatives may become increasingly available.
When such changs occur, and a.
4 when they have a material effect on the analysis, separate markets should be 5
defined in each period.
6 IV. RELEVANT MARKETS 7
Q. What is the relevant market (or markets) in this case?
s A.
The markets relevant to the competitive impact of tht merger are 9
retail and bulk power markets in which the merging entities compete.
My L
10 assersment of past trading patterns, load and resource reports and relative 11 reliance on alternative fuels resulted in the identification of four Western 12 Systems Coordinating Council (WSCC) areas as relevant bulk power markets.
13 These are:
(1) the market for bulk power sales in the California Area; (2) the 14 market for sales in the Arizona-New Mexico Power Area; (3) the market for 15 excess energy and capacity within the Northwest Power Pool Area; and (4) the 16 market for sales in the Rocky Mountain Power Area. I have also identified and i
}
17 assessed the retail and coal markets in which the merging entities compete.
/
j 18 Q.
Why do you find bulk power to be the relevant product for con-19 sidering the competitive aspects of this merger on sales among utilities?
I 20 A.
Bulk power is the relevant product for considering the competitive 21 aspects of this merger because there is a significant ability to substitute among i
i 22 individual bulk power services in both supply and demand, la addition, the 23 patterns among transactions in these services vary both seasonally and over a 24 period of years.
It is more useful to assess the market as s whole than it is to L
a 25 examine the ladividual parts.
i 26 Q.
Please explain why substitutability in both supply and demand led you l
.r i
n e TQ*
l L
_ms s
- a Exhible No.14 Page 10 1
to choose bulk power as the relevant product marke't.
2 A.
On the supply side, the same generation units and transmission lines 3
can be used to provide a variety of electrical services.
For example, electric 4
supply can be either firm or nonfirm and each of these has several variations.
5 The electric service can also oe provided for a wide variety of periods and in 6
any physically possible quantity.
Since the same firms, using the same types of 7
equipment, can offer all of these producu, it is most useful to consider them in 8
one bulk power market. On the demand side, each utility requires a firm supply 9
of bulk power for sale to its retail and wholesale customers.
However, this 10 firm supply can be made up of an almost endless variety of combinatiens of Il inputs from either the utility's own system or from purchases.
l 12 Q.
Why does the variety of trading patterns over a period of time 13 support the use of an aggregate bulk power market?
14 A.
The proper focus of a merger inquiry is on present and future effects 15 of the merger.
Over the last 10 years, the nature of markets in this region, as 16 well as others, has changed substantially.
Needs change for capacity in some 17 periods and for energy in others.
The most significar*t form of sale today may 18 become much less significant tomorrow as fuel prices, capacity and loads 19 continue to change.
In the WSCC aret. there are also dramatic changes in the 20 type and direction of transactions from season to season.
All of these changes 21 support the appropriateness of the more gene.al bulk power definition.
22 Q. In defining all of your markets, how has the proper time frame been 23 factored into your definition and analysis?
24 A.
In evaluating the relevant markets, while I have censidered both the 25 recent past expellence and projections for the future, it is clearly in future 26 markets that the effects of the merger will be played out.
In general, I have n e Ta'
,s.
L' phlblt No.14 Page 11 1
considered markets as they are expected to be over the next decade or so based 2
on current plans and forecasts.
3 Q. Would you please describe how you evaluated the structural and 4
lastitutional elements of these markets and what information you relied on?
5 A.
To identify the structural and institutional elements, including the 6
number and relacive market strength of the participants in the bulk power 7
markets I have studied maps and public reports outlining the transmission grid 8
and power flows for the western United States and Canada, past and forecast 9
electric
- demand, available and planned resources (generating capacity),
10 transm!ssion links, institutional arrangements (such as power pools), existing 11 contractual commitments and cost-related information.
Specifically, I have 12 relied on seve:11 WSCC reports, annual reports of electric utilities filed with 13 the FERC (Form No. Is), numerous financial and operating statistic reports 14 pub!1shed by the U.S. Department of Energy, U.S. Department of Agriculture 15 (Rural Electrification Administration), U.S. Department of the Interior-Eureau of 16 Reclamation (USBR), BPA, Westarn Area Power Administration (WAPA) and 17 Ecenomic Regulatory Admini:'. ration.
18 From these sources, I was able to identify the major power providers 19 in each region, the transmission links and intertie capacities, the seasonal and 20 annual demands for power and energy in the various regions and the institv-21 tional arrangements which affect bulk power sales between the regions.
Each 12 area in the WSCC region was evaluated separately in terms of generation, 23 demand and the likely volume of net imports or exports over the next decade.
24 Q. How did you go about defining relevant geographic bulk power 25 markets?
26 A.
I started with the regions wh!ch have been established by the WSCC.
n e Ta'
.. o a
Erhlblt No.14 Page 12 1
The WSCC is a voluntary consortium of electric utility organizations fermed in 2
1967 whhh establishes reliability criterit and procedures for operating ani 3
planning electric power systems in the western part of the United States and 4
adjacent areas of Canada and Mexico.
The WSCC has 61 member system:;:
19 5
investor-owned utilities; 18 public power systems; 16 municipal utilities; four 6
federal agencies; three Canadian systems; and one Mexican system.
Member 7
utilities provide most of the electric service in the states of Washington, 8
Oregon, California, Arizona, New Mexico, Nevada, Utah, Idaho, Montana, 9
Wyoming and Colorado.
Member systems also provide electric service to 10 portions of South Dakota, Nebraska, Texas and to the Canadian provinces of Il British Columbia and Alberta.
Another member system provides electric service 12 to the northern portion of Baja California, Mexico.
Schedule 3 lists the WSCC 13 member systems.
14 The WSCC region is divided into four areas:
(1) the Northwest 15 Power Pool Area; (2) the Rocky Mountain Power Area; (3) the Arizona-New 16 Mexico Power Area; and (4) the California-Southern Nevada Power Area.
17 Schedule 4 is a map of the region showing the location of the individual power 18 areas.
These regions are established on the basis of differences in resources 19 and loads and are those that the WSCC itself uses for planning purposes.
I 20 Because the WSCC is a voluntary organization consisting of all of the major 21 utilities in the region and many smaller ones as we!!, these areas represen 22 something of a consensus among the major suppliers of pomer and energy in the 23 region as to the major power areas and their boundaries.
Generally speaking, 24 the transmission interconnections within these regions are more comprehensive t
i 25 and less constraining than are interconnections between regions.
At least eht 26 of the merging firms is a participant in each of the four WSCC regions. These L
n e ra'
c, Erhlbli No.14 -
.Page 13 1
regions are logical areas within which to assess trade. patterns and the 2
competitive impact of the merger.
The map of load areas, reproduced from a 3
WSCC report, shows the outline of the four areas within the WSCC.
This map 4
was introduced by Mr. James D. Tucker as his Schedule'9 of Exhibit 13.
For 5
ease of reference, I have included a copy as Schedule 2 to this testimony.
6 Q.
Before discussing the individual WSCC regions, have you examined the 7
relationship between the size of the merging firms and the overall capacity in 8
the region?
9 A.
Yes. In my Schedule 5, I show the rank order by generation capacity 10 of all of the utilities in the WSCC. PP&L is the eighth-ranked firm and UP&L 11 is the eleventh-ranked firm.
The combined firm would rank fifth with a total 12 capacity of 7,229 megawatts.
This represents slightly over $ percent of the 13 total capacity in the WSCC.
A HHI based on the capabilities of WSCC systems 14 is 676 before the merger and would be 689 after the merger for a difference of 15 13 points.
16 Q. Would you explain what a HHI is and how it is calculated?
17 A.
Yes. The iiHI is a measure of market concentration.
It is calculated
[
18 by squaring and adding together each firm's percentage of the market.
The I
19 more concentrated are sales among the highest ranked companies, the greater 20 will be the resulting index.
21 Q. Is there some standard for interpreting HHis in the context of a L
22 merger?
23 A.
Yes.
The Department of Justice (DOJ) has established Merger Guide-24 lines which include a set of criteria for interpreting HHIs and the changes that 25 would result in HHis as a consequence of a merger.
These guidelines are 26 incluoed with this testimony as Schedule 20.
n e Ta'
i Exhibit No.14 Page 14 1
The guidelines indicate that markets with HHis below 1,000 are 2
considered unconcentrated and all mergers are permitted despite entry barriers 3
and otner factors.
Between 1,000 and 1,800 ease of entry and other factors are 4
considered.
Mergsrs in this area will generally not be opposed only if they 5
raise the HHI by less than 100 points.
A post-merger HH1 of above 1,800 is i
6 co3sidered a highly concentrated market.
If the post-merger HH1 exceeds 1,800, 7
and entry is not easy, the DOJ will generally seek to block a merger that would 8
increase the HHI by 50 or more points.
An increase of less than that would 9
not generally give rise to a DOJ challenge.
10 Q. Do you believe that thess HHI standards are appropriate for assessing 11 this merger?
12 A.
No.
I believe that several factors combine to make the HHI stand-13 ards less applicable to these circumstances.
The presence of regulation, the 14 practice of small firms entering into joint ventures, the fact that several of the 15 most sign lficant entities are government. agencies, the exclusion of potential and 16 4 elf-supply sources from my calculations of supply sources within the areas
'7 combine to make the DOJ standards for approval of a merger higher than would 18 be appropriate.
19 Q. Have you assessed the present trade patterns among the four bulk 20 power markets you have idantified?
21 A.
Yes.
Schedule 6 shows the purchases and sales among markets in 22 1986.
The most significant net sales were from the Northwest Power Pool Area 23 to the Rocky Mountain Power Area and from the Northivest, Rocky Mountain 24 and Arizona markets into the California Area.
25 Q. Have you also examined the projected loads and resources of these 26 markets to determine the likely pattern of futare trade flcws?
n e Ta*
Exhibit No.14 Page 15 1
A.
Yes.
Schedules 7 to 11 detail the projected loads and resources of 2
these markets for 1987 and 1996.
Schedule 7 summarizes capability, loads and 3
imports for each of the markets and provides a breakdown of capacity by fuel 4
type.
Schedule 8 provides a summary of loads and energy sources in gigawatt-5' hours for each of the markets.
Schedules 9 through 11 provide generation by 6
fuel type in 1987, additions between -1987 and 1996 and projected generating 7
capability at the end of 1996.
8 Q. Would you briefly summarize the significance of the information 9
presented in Schedules 6 to 11 to your analysis?
10 A.
Yes. This information is used to describe the pattern of trade in the 11 WSCC region as it is now and as it is projected to change over the next 10 12 years.
This pattern of trade will determine the relative significance of bulk 13 power markets with respect to which the merger is to be examined. My discus-14 sion of each of the bulk power markeu is based on the information in these 15 schedules.
16 A. The California Area 17 Q. Referring to the analysis of trade patterns among regions, please 18 exp'ain the significance of the California market.
19 A.
Sales of bulk power to utilities in the ' California Area are, and are l
20 projected io continue to be, the largest and most significant net transfer i
1 2i between WSCC areas.
Purchases by California Area utilities of bulk power from 1
22 the Northwest Power Pool Area and other outside sources historically have been l
23 substantial.
The merging parties have themselves made substantial sales into l
24 the California Area.
The details of loads and resources for the California Area.
l 25 as well as the sales into this area by the merging parties, are provided in 26 Schedules 12 through 16 as well as Schedules 6 to 11.
Projections of loads and l
I n e ra' l
4 Exhibli No.14 Page 16 I
resources indicate that the California Area is likely to continue to be a 2
substantial net importer of capacity and energy.
Percentage reserves in the 3
California Area are, and are projected to remain, the lowest of 'he WSCC power 4
areas.
The California Area also has, and is projected to continue to have, the 5
greatest percentage reliance on oil-and gas-fired generation.
The market for 6
bulk power sales in the California Area clearly is relevant to the assessment of 7
the proposed merger.
8 Our assessment of external resources must clso consider internal 9
alternatives.
"Qualifying f6cilities' (QFs) compete with the California utilities' 10 own generation as well as that of utilities in other regions to supply the 11 increased capacity and energy requirements of the California Area.
These 12 suppliers within the region are not restrained by external transmission 13 availability and, in effect, place a competitive ceiling on the price that will be 14 paid for external capacity at.4 energy.
Nonetheless, the California Area will 15 continue to be a net importer of energy and power.
It appears that the area 16 will be fired by oil and gas at the margin, making it vulnerable to changes in l
l 17 the prices of those fuels.
18 In addition, it is important to note that within the California Area it 19 is difficult, if not impossible, for utilities to add new baseload benerating plants l
20 because of environmental and other factors.
Therefore, load growth must be 21 met from additions to sources outside the area, QFs or other independent 22 sources within or outside of the area, and from additions to imports of energy 23 and power from other utilities.
l L
24 Q. Have you assessed the relative role of the merging utilities in the t
l 25 California market?
l 26 A.
Yes.
Schedules 17 to 19 provide the rankings of external suppliers l
k n e Ta'
. w.
Exhibit No.14 Page 17 1
into the California market.
Sched ule 17 provides the ranking by total imports 2
in 1986 of the five leading California utilities.
The merging utilities are ranked 3
sixth and twelfth.
The combined companies would have ranked third.
Their 4
total sale's would have constituted slightly over 8 percent of the total.
5 Schedule 13 shows the rankings in terms of 1984 firm energy sales.
PP&L is 6
the fourth-ranked seller with slightly less than 6 percent of the sales.
UP&L 4
7 made no firm energy sales into this market.
Schedule 19 shows 1984 firm 8
capacity sales into the California Area.
PP&L is the eighth-ranked seller with 9
2 percent of the total sales. UP&L had no capacity sales into California.
10 In sum, the merging con:panies account for substantially less than 10 percent of the total external sales into the California Area and much less of 12 the firm sales.
The merger will have very little or no effect on market 13 concentrations.
14 Q. Did you calculate HHis for Schedults 17 to 197 15 A.
Yes. The HHI for total sales in 1986 is 1,209 and the. merger would 16 increase it by only 27 points.
This is a conservative (that is to say, 17 overstated) calculation because it includes only the energy imports of the five 18 leading utilities in California:
Pacific Gas and Electric Company (PG&E),
19 Southern California Edison Company (SCE), San Diego Gas and Electric Company 20 (SDG&E), Los Angeles Department of Wtter and Power (LADWP) and Sacramento l
21 Municipal Utility District.
The HHI etJeulated for 1984 firm capacity sales is 22 slightly above 2,000, but is not changed at all by the merger since only one of 7
l 23 the merging companies made such sales. The HHI for firm energy sales in 1984 24 is 2,570 but, as was the case with firm npacity, the HHI would not change at 25 all as a result of the merger since UP&L did not make any such sales.
26 Q. Would you briefly describe the transmission network linking the l
neTQ*
.,o Exhlhir No.14 Page 13 s
California Area with the other regions?
2 A. ~ Yes.
The major transmission paths for the WSCC region are depicted 3
graphically in Mr. Tucker's Schedule 9 of Exhibit 13, which I previously 4
introduced as my Schedule 2.
This schedule shows the essence of the existing 5
WSCC transmission corridors and the near-term planced additions.
The circles 6
represent separate generatior4 areas wl:h the relative amount of generation 7
within that area depicted by the size of the circle.
Similarly, the size of the g
lines connecting the circles indicates the transmi5sion capacity bet'.veen the 9
geterating areas.
10 Currently, the California Area is accessible from the Northwest Power 11 Pool Area and the Arizona-New Mexico Power Area.
Total east-to-west 12 transmission capacity from the Arizona New Mexico Power Area is 5.620 13 megawatts.
The parties controlling these lines include LADWP, Nevada Power 14-Company (NPC), WAPA, SCE, Arizona Public Service Company (APS), SDGAE, 15 and the Imperial Irrigation District (!!D).
16 Total north-to-south transmission capacity into the California Area 17 from the Northwest Power Pool subregion is 6,430 megawatts.
The parties 13 controlling these lines include BPA, PG&E, PP&L, Intermountain Power Agency 19 (IPA) and Sierra Pacific Power Company (SPP).
20 Q. What portions of this transmission system are controlled by the I
j 21 merging entitles?
i l
22 A.
Very little of the direct transfer capacity from the Northwest Power 23 Pool Area to the California Area is controlled by PP&L, and none is controlled 24 by UP&L.
Total interregional capacity into the California Area is 12,050 l
i 25 me gawatts.
The total PP&L entitlement is less than g percent of the direct l
26 north-to-south capability between the Oregon-Washington section of the n e ra'
Exhibit No.14 Page 19 1
Northwest Power Pool Area and the California Area and about 3.3 percent of 2
the total transfur capacity it'o California.
Near-term capacity additions will 3
lower this percentsge.
UP&L has no firm access to the California marke t.
4 Thus, the merger will not result in any concentration of this access.
5 B. The Arizona-New Mexleo Power Area 6
Q. Please explain the relevance of tbs Arizona-New Mexico Power Area.
7 A.
The sales into the Arizona-New Mexico Power Area by the merging 8
parties and other Northwest Power Pool utilities, as well as by utilhics in tne 9
Rocky Mountain Power Area, have historically been substantial (see Schedules 10 21 through 26). There continue to be sales into this area by UP&L, u well as 11 other Northwest entities.
Sales currently are primarily during the outages of 12 baseload generation in the Arizona area.
Because of the contin'2ing volume of 13 these sales, this region is a relevant market, notwithstanding the fact that its 14 significance has been greatly reduced.
This reduction in significance, at the 15 current time and for the foreseeable future, is a result of the fact that this 16 area is expected to have enough generation reserves to be self-sufficient and to 17 be a net exporter into the California Area (see Schedule 7).
Moreover, genera-18 tion in this area is dominated by relatively low-fuel-cost nuclear and coal 19 facilities making economy purchases from other regions less likely.
4 20 Q. What is your assessment of the net demand for bulk power imports or 21 expo'rts in the Arizona-New Mexico Power Area?
22 A.
As was indicated in Schedules 7 and 3, this region currently has 23 generation substantially in excess of iu peak load.
Both generating capability 24 and load are expected to grow rapidly over the next decade (see Schedules 21 3
25 through 26). The region is dominated by coal and nuclear energy sources. The 26 combination of the relatively low fuel costs and the reuonably high levels of t
n e T R*
.__. ~ _ _._
Exhibli NQ Page 20 1
present and forecast reserves reduces the likelihood that the e will be a 2
significant demand for capacity or energy from outside sources for the fore-3 reeable future. This region is now, and is likely to continue to be, a net seller 4
into the California Area, thereby reducing the potential market power of Pacific 5
Northwest utilities including the merging parties.
6 Q. Please describe the transmission system between the Arizona-New 7
Mexico Power Area and other regions.
g A.
The total north-to-south capacity on the lines connecting the 9
Arizona-New Mexico Power Area with the Rocky Mountain Power Area is 1,850 10 megawatts.
The controlling parties are WAPA and Public Service Company of 11 New Mexico (PSNM).
UP&L controls a transmission line that connects the 12 Arizona-New Mexico Power Area to the Northwes6 Power Pool Area.
North-to-13 south capacity on this line is 600 megawatts.
Bulk power sales can also be 14 made from the California Area into the Arizona-New Mexico Power Area. Total 15 west-to-east capacity for such transactions is 2,314 megawatts.
The controlling 16 parties include WAPA, NPC, SDG&E, APS, IID, LADWP and SCE. Total inter-17 regional transmission capacity into the Arizona-New Mexico Power Area from 18 the other WSCC subregions is 4,764 megawatts.
UP&L controls approximately 19 12.6 percent of the total interregional capacity.
PP&L does not control any 20 transmission access to this area.
Hence, the merger would not result in an 21 increase in the percentage of control by a single entity.
22 Q. Some parties have expressed concern that the merger will result in 23 greater concentration of control over transmission access to the Arizona-New l
24 Mexico Power Area. Would you address this issue?
25 A.
Yes.
First, because PP&L does not control any transmission access to 26 the Arizona-New Mexico Power Area, there will be no concentration of direct l
l n e ra-
Exhibit No.1J t
Page 21 i
1 access.
Second, from the perspective of purchasers in Arizona, there are many 2
sellers and many methods of access, including not only the Pinto-to-Four 3
Corners line controlled by UP&L, but other lines capable of transferring energy 4
from the Rocky Mountain Power Area and, if economic, from the California 5
Area.
Third, if the objection to the merger is bued on access to the 6
California market through Arizona, that access is unchanged by the merger and 7
relates to only one of the many sources of incremental power and energy to 8
California. I have dealt with California's alternatives in Section IVA above.
9 C. The Northwest Power Pool Area 10 Q. Is the Northwest Power Pool Area a net importer or exporter of bulk 11 power 7 12 A.
The Northwest Power Pool Area is projected to be e net exporter of 13 bulk power in both summer and winter throughout the 1987-1996 period.
14 Schedules 7 to 11, which ! introduced earlier in my testimony, summarize the 15 present and prospective loads and resources status of this region.
Further 16 details are provided in Schedules 27 through 31. This region has predominantly 17 hydroelectric and coal generation and is projected to be a substantial net 18 exporter over the next 10 years.
The relevant bulk power market for this 19 region is the market for sales among utilities in the Northwest.
20 Q. Would PP&L and UP&L, if merged, have significant market power in 21 the Northwest Power Pool Area?
22 A.
Within the Northwest Power Pool Area both PP&L and UP&L are 23 important utilities.
However, even combined, they have only a small percentage 24 of the generating capabilities of the region.
Figures for the expected winter 25 peaks indicate that, if merged, the combined utility will control approximately 26 12 percent of generating capability in 1987 and about 9 percent in 1996 within i
n e Ta' q
f Exhibit No.14 Page 22 I
the Northwest Power Pool Aiea, not enough to cause concern with any potential 2
for significant market power (see Schedules 32 and 33).
3 As Schedule 34 indicates, BPA has well over twice as much genera-4 tion as do the merging utilities combined.
Similarly, their combined shares of 5
the total projected net margin of reserves over requirements in the area varies 6
from 2 psreent to 10 percent depending on the season and the year.
This is 7
illustrated in Schedule 33.
Schedule 35 shows the rankings of Northwest 8
utilities in bulk power sales within the Northwest Power Pool Area.
It indi-9 cates that the merging parties are ranked eleventh and twelfth, and that the 10 merged utility would rank tenth with combined sales equal to about 4 percent, 11 Q. Have you calculated HHIs for the Northwest Power Pool Area?
12 A.
Yes. I calculated the HH1 for generation capacity and for bulk power 13 market sales.
For espacity, the pre-merger HHI is 1,311.
The merger would 14 increase it by about 58 points. For bulk power sales, che HHI is 1,316 with the 15 merger increasing it by y four points.
The merger clearly would pass the 16 DOJ Merger Guide!!ne's HH1 standard in t'ase markets, r
17 Q. Please describe transmission capacity as it relates to the Northwest 18 Power Pool Area.
19 A.
Total capacity into the Northwest Power Pool Area from California is 20 4,814 megawatts.
The controlling parties are PP&L, BPA, PG&E, IPA and SPP.
21 PP&L controls a total of 330 megawatts of the south-to-north capacity into the 22 Northwest from California.
23 Total transmission capacity frot. the Rocky Mountain Power Area into 24 the Northwest Power Pool Area is 3,692 megawatts.
Of this capacity, PP&L 25 controls $26 megawatts and UP&L controls 370 megawatts.
The remaining 26 capacity is controlled by WAPA, Tri-Stste Generation and Transmission i
n e Ta'
a e.
Erhtbit No.14 Page 23 1
Association, Inc. (TSGT),' Basin Electric Power Cooperative (BEPC), Black Hills 2
Power and Light Company (BHPL), Deseret Generation and Transmission 3
Cooperative (DGT) and Montana Power Company (MPC).
Capacity from the.
4 Arizona-New Mexico Power Area consists of the 600-megawatt line which UP&L 5
controls.
The total interregional transfer capacity into the Northwest Power 6
Pool Area is 9,106 megawatts.
The combined PP&L and UP&L entity would 7
control approximately 20 percent of this total.
8 D. The Rocky Mountain Power Area 9
Q. Is the Rocky Mountain Power Area a net exporter or importer of 10 bulk power?
11 A.
The Rocky Mountain Power Area is a net exporter of bulk power in 12 both the summer and winter seasons.
As can be seen in Schedule 37, net 13 exports in 1987 are expected to be 904 megawatts for the summer and 819 14 megawatts for the winter.
Very little change is expected by 1996.
Thus, this 15 area will likely remain a net exporter over the next decade.
16 Q. What assessment have you made regarding the Rocky Mountain Power 17 Area?
18 A.
PP&L does serve in a portion of Wyoming and generates in the Rocky 1
19 Mountain Power Area and transmits to its facilities and loads in she Northwest 20 Power Pool Area.
However, while PP&L sus..
some utilities, such as BHPL, 21 it is not a significant supplier to utilities in the region.
And while PPAL 22 purchases from Rocky Mountain Power Area utilities, such as Rocky Mountain 23 Generation Cooperative, it is not a major customer.
Traditionally, PP&L.nd j
24 UP&L have had limited bulk power dealings within the Rocky Mountain Power 25 Area.
The fact that load growth in this area is not expected to be exceptional l
26 and that its resources are expected to be both economleal and adequate for its D S T D*
1 4
- - - - -., +
.-,,-,,--n-,,---,,,,-n_----n-..--n---.,-
,-_.n.mn-,,,-
Exhibit No.14 Page 24 1
needs indicates that this is likely to continue to be the case.
This is 2
illustrated in Schedules 36 tc 41.
3 Q. Dr. Landon, do PP&L and UPai make substantial ame.unts of sales in 4
the Rocky Mountain Power Area?
5 A.
No, they do not.
As can be seen in Schedule 42, the two utilities 6
together supplied only 2.3 percent of the energy consumed in the Rocky 7
Mountain Power Area and 2.5 percent ol' the power in 1986.
Virtually all of 8
the energy and all of the power was from PP&L and would not be affected by 9
the merger. The UP&L sale was of energy only. These amounts are very sr..all 10 and do not represent a significant impact within the Rocky Mountain Power 11 Area.
12 Q.
Have you assessed transmission as it relates to the Rocky Mountain 13 region?
14 A. Yes.
The Rocky Mountain Power Area is accessible from the North-15 west Power Pool Area and the Arizona-New Mexico Power Area.
Wesi-to-cast 16 espacity from the Northwest is 3,562 megawatts.
The controlling parties are l
17 PP&L, UP&L, WAPA, BHPL, BEPC TSGT, DGT and MPC. From the Arizona-18 New Mexico Power Area, a possib!: 800 megawatts of capacity exists for the 19 south-to-north flow.
WAPA and PSNM control those lines.
Total interregional l
20 transfer capacity into the Rocky Mountain Power Area is 4,362 megawatts.
21 Approximately 20 percent would be controlled by the merged utility.
22 E. Factors Which Could Materf ally Affect the Bulk Power Market Analysis 23 Q. What factors could change the expected relative demands for imports 24 and exports amot:g the WSCC regions 7 25 A.
Changes in the relative fuel costs of oil and gas, particularly in the 26 California Area, or an acceleration in the rate of load growth, especially in the n e ra'
Ld11blLt y Page 25 l
1 Arizona-New Mexico Power Area, could change current import / export forecasts 2
for the WSCC region.
3 Q. How would changes in relative fuel costs affect the expected 4
outcome?
5 A.
An increase in the relative prices of oil and gas would have the 6
effect of raising incremental energy costs in the California Area relative to 7
those in other areas.
California utilities would have even greater incentives to 8
generate less and import more. This would cause the area to become even more 9
Import-dependent.
10 Q. v/ hat changes would likely result from higher than expected growth Il in the Arizona-New Mexico Power Area?
1 12 A.
If the level of demand in the Arizona-New Mexico Power Area, 13
~ already forecast to grow at the fastest rate among the power areas, were to 14 grow even faster than forecast and outstrip the current plans for additional 15 generating capacity in the area, then that area would be less able to export 16 energy and power to the California Area and more likely to import energy from 17 the Northwest Power Pool Area and the Rocky Mountain Power Area.
While 18 this would te'ad somewhat to reduce alternatives available to California, the 19 Arizona and California markets would remain competitive. This result would not 20 be materially affected by the merger.
21 Q.
Dr. Landon, would any of the potential differences in circumstances 22 that you have just discussed change your evaluation of the competitive situation i
23 in the markets you have discussed?
l 24 A.
No, these markets would remain competitive urider any circumstances 25 that I consider realistic.
j 26 F. Retall Market nera'
-m
Exhlblt No.14 Page 26 1
Q. Will you describe the principle forms of retail competition about
~
2 which the FERC historically has expressed concerns?
3 A.
Yes.
The FERC historically has considered yardstick, industrial 4
location, fringe area and franchise competition.
Yardstick competition refers to 5
the use by utilities or regulators of the performance of other utilities as an 6
index against which to gauge the relative performance of a given utility.
7 Industrial location competition refers to competition among utilities to attract 8
newly locating or expanding industrial firms for which electricity is a 9
significant input.
Fringe area competition is competition to serve customers 10 who locate such that they can be served by two or more utilities.
Franchise competition is competition for the franchise to serve an area presently served 12 by another utility.
13 Q. Would you identify those areas in which PP&L and UP&L may 14 compete 7 15 A.
Yes.
There is at least the potential for yardstick and industrial 16 location competition.
17 Q. Why do you not include franchise or fringe area competition?
18 A.
The retail service areas of the two utilities are adjacent at only a 19 few points.
There are only two states in which both utilities serve.
- Moreever, 20 both generally serve exclusive areas designated by state law and/or regulation.
21 There has been no historical transfer of service area between them and I know 22 of no present proceeding to make such a transfer.
There are many other i
23 utilities adjacent to the retail areas of the merging parties which would be 24 alternate suppliers if there were a serious attempt to disenfranchise either of I
25 the merging utilities.
In sum, the prospect of franchise competition between 26 the merging utilities is too remote to warrant further consideration.
n e Ta'
.. =
..e Erhlblt No.14 Page 27 1
1 Q. What conclusions have you reached with respect to industrial location 2
cornpetition?
3 A.
I hai concluded that the merger will not materially affect whatever 4
lodustrial location competition there may be.
As I indicated in response to the 5
previous cuestion, the merging utilities are adjacent at only a few points.
6 There may be industrial concertis that consider location in either the PP&L or 7
UP&L service areas.
If there are, it is probable that they are also considering 8
locations in the areas served by other Northwest utilities.
The area relevant to 9
an industrial concern for which electricity was a very high percentage of total 10 cost should, at the least, Inc..ade adjacent low-cost utilities.
The market is 11 more likely to be the entire Northwest.
The merger of PP&L and UP&L will 12 not significantly reduce competition in this market.
13 Q. Please state your conclusions with respect to yardstick competition.
14 A.
The merger will not materially reduce yardstick competition.
While state commissions ~ may make comparisons among utilites, the merger will not 16 reduce the number of Northwest utilities significantly.
Moreover, since the two 17 serve quite different markets and have very different combinations of gen-18 ersting resources, the prospect of meaningful yardstick comparisons between 19 them is remote.
20 G. Coal Market 21 Q. Dr. Landon, in your assessment of the impact on the coal market.
22 how have you defined the coal market?
23 A.
I have not defined a specific coal market as PacifiCorp and UP&L use 24 a variety of different types of coal in their plants and own a variety of 25 different types of coal resources.
In addition, their plants and coal mines are 26 spread out over several states.
Properly defining coal markets for PacifiCorp n e rQ*
r
j i
Erhlbli No.14 Page 23 i
and UP&L would require looking at each plant and mine and determining the t
2 actual and potential coal supply competitors for each.
This level of detailed 3
analysis is not required for the purpose of reviewing the merger.
4 Instead, I examined a coal area composed of coal produced in 5
Colorado, Wyoming, Montana, Utah, New Mexico, Arizona and Washington and 6
delivered to utilities.
This area corresponds w.ith Bureau of Mines District Nos.
7 16 to 20,22, and 23. This is roughly the same geo5raphic area as the WSCC.
8 Q. How competitive is the coal market that you have der aed?
9 A.
Schedule 43 shows 1986 deliveries to utilities by the large t coal 10 producers in ' tine coal market by rank.
The schedule also shows two HHis for 11 the market:
one for the present marke; and one for the raarket if NERCO's 12 and UP&L's coal operations were combined.
The indices are both below 800' 13 indicating that the coal market is presently competitive and would remain so 14 even if NERCO's and UP&L's coal operations were combined.
15 Q. Dr. Landon, what would the impact of the merger be on the coal 16 market?
4 17 A.
the merged companies' plans for their coal operations are discussed 18 in the testimonies of Mr. Ver! R. Topham and Mr. Dennis P. Steinberg.
My 19 review of their testimony indicates that there would be little or no impact on 20 the coal market due to the merger.
This conclusion is based on the following:
21 (1) the me:ged companies plan to keep UP&L's coal operations separate from 22 PacifiCorp's NERCO coal subsidiary; (2) the merged companies do not plan to 23 change coal procurement activities; (3) the merged companies would control less 24 than 6 percent of the uncommitted coal reserves in the coal market; (4) four of 25 the five PP&L coal-fired power plants are jointly owned with wholesale 26 competitors and those competitors also wholly own or partially own and control n e ra'
Erklblt No.14 Page 29 1
the attendant cok! supply; and (5) the only coal sales to an actual or potential 2
wholesale power competitor is a contract between NERCO and Platte River 3
Power Authority to provide coal for the 250-megawatt Rawhide 1 unit undar 4
flexible terms.
5 Q. How does keeping UP&L's coal operations separate from NEP.CO 6
lessen the impact of the merger on the coal market?
7 A.
Keeping UP&L's coal operations separate from NERCO allows these 8
operations to remain focused on serving the Hunter and Huntington coal-fired 9
power plants and retains the present competitive balance among Utah coal 10 producers.
11 Q. How does retalning the present coal procurement strategies lessen the 12 impet of the merger on the coal ntarket?
13 A.
The present coal procurement strategies for the individual companies 14 are designed to lower or stablitze power prices within the framework of existing 15 contractual arrangements.
By continuing to work within the framework of 16 existing contrserual obligations, the merged companies will not change the 17 present competitive balance in the coal market.
As part of present coal 18 procurement strategies, the merged companies will likely !ncrease
- use of 19 outside, or nonaffiliate, coal.
This will increase market opportunities for 20 nonaffiliate coal suppliers and lead to a more competitive overall coal market.
21 Q. Would the merger restrict the access to coal by wholesale power 22 competitors?
23 A.
The merged companies would control less than 6 percent of the 24 uncommitted coal reserves in the coal market.
With control ov r such a small 25 amount of reserves, there is little reason to suspect that this would lessen 26 competition or restrict access to coal by competitors, neTa'
.~.
r t
Erhlblt No.14 Page 30 i
1 Q. How does the lack of coal sales by NERCO and UP&L to actual or 2
potential competitors affect the fuel procurement position of other wholesale 3
power competitors?
'4 A.
While the UPAL coal mines are one of the largest coal operations in 5
Utah and NERCO is one of the largest strip mine coal companies in the United 6
States, UP&L and NERCO's self-supply and the predominance of NERCO's sales 7
to ut!!ities outside of WSCC means that neither has any contrretual control 8
over the independent coal supply of wholesale competitors.
The one contract 9
that NERCO has with a potential wholesale competitor, ths Platte River / Rawhide 10 Unit I contract, has qui'.e flexible terms and allows Platte River to enter the coal market to take advantage of low-priced, short-term coal opportunities.
12 The merged company will not have the ability to restrict access to 13 the coal market by any wholesale pewer competitors.
The merged company will 14 not affect competition by other coal suppliers for the fuel supplies to wholesale 15 power competitors.
16 V. THE MERGER GUIDELINT.S AND OTHER CONSIDERAYiONS 4
17 Q. Dr. Landon, can you describe more fully the DOTS Horizontal Merget 18 Guidelines which you have included as Schedule 207 19 A.
Yes.
The Merger Guidelines reflect DOJ enforcement policy.
The 20 Merger Guidelines set out 'a five-point 'pectocol' for evaluating the possible 21 competitive impact of a horizontal merger.
The five steps involve defining the 22 relevant market, meuuring concentration in that market, evaluating the likeli-23 hood of entry and successful collusion and analyzing any efficiency benefits 24 (primarily cost savings).
Ease of entry and concentration (as measured by the 25 HHI) are generally given the most weight in evaluating proposed mergers under 26 the Merger Guidelines.
However, the Merger Guidelines are premised on the n e Ta' i
w
o z..
Exhlk.It No.14 Page 31 1
recognition that significarit cost savings (efficiencies) can flow from mergers 2
and, therefore, the relative weight given to efficiency benefits vis-a-vis ease of 3
entry or concentration may vary according to circumstance.
In fact, under the 4
1984 revisions of the Merger Guidelines, even mergers likely to raise prices are-l 5
permitted if the parties can demonstrate that the merger is ' reasonably 6
necessary' to create significant cost savings or other e ficiency benefits.
r 7
Q. Have you considered entry conditions into the bulk power market?
8 A.
Yes.
While capital requirements, lead times and regulatory barriers 9
are significant, entry at the generation level has been, and will continue to be, 10 substantial.
Entry occurs frequently and includes many firms.
In recent years, 11 large rimbers of small cogenerators and independent generators have entered 12 the market and are presently supplying over 6,900 megawatts of generation in 13 the WSCC region.
An sdditional 7,800 megawatts of cogeneration and small 4
14 power production is either under cons'ruction or being planned in the WSCC 15 region.
These entities, fro.n which utilitics are required to buy at the level of 16 their avoided costs, are not constrained by external transmission limitations and 17 provide a competitive price ceiling under which external suppliers must bid.
In 18 addition,. the acceptance of ' extra
- utility generation projects designed to serve 19 the bulk power market indicates that barriers to entry to the generation portion 20 of the bulk power market are reduced from the past. By ' extra' utility genera-21 tion projects, I mean projects which have little or no utility involvement and 22 are not subject to normal state regulatory commission oversight.
Two such 23 projects are being developed in the WSCC:
(1) the Dineh Project in the I
l 24 Arizona dew Merico Power Ares; and (2) the Thousand Springs Project in the 25 Wrthwest Power Pool Area.
The Dinch 1roject in New Mexico is a joint 26 venture of the Navajo Tribe, General Electric Company, Bechtel Power 1
4 n 43 T W
4 Erhlblt Nd Page 32 l
1 Corperation, Combustion Engineering, Inc. and affiliates of PSNM for four 500-2 megawatt coal-fired units.
The Thousand Springs Project in Nevada envisions 3
up to eight coal-fired units with an aggregate total capacity of up to 2,000 4
megawatts.
The project is being developed by Sierra Pacific Resources, the 5
owner of SPP, but the utility will limit its ownership share to 14.5 percent.
6 The balance of the ownership will be divided among nonutility participants 7
which may include Babcock & Wilcox, Rocky Mountain Energy (the coal-mining 8
unit of Union Pacific), and Genera! Electric.
The project was exempted from 9
regulation by the Nevada Public Service Commissica through speciallegislation.
10 Q. Have utility sources continued to install additional generating capacity 11 in the WSCC7 12 A-Yes.
In the three-year period 1984 through 1986, 13,233 megawatts 13 came on line in the WSCC.
Forty-five utilities had ownership shares in this
?
14 capacity.
Over the last decade, generating espacity in the WSCC increased over 15 40 percent, l
16 Q. How substantial are the barriers to entry to the transmission portion 17 of the bulk power market?
r 18 A.
While the barriers to entry to the transmission portion of the bulk 19 power market are higher than for the generation portion, they are still low 20 relative to the resources of the utilities in the region.
This ein be seen :n the fl large number of transmission lines either under construction or in the planning 22 stage.
Transmission lines often have to go through a certificate of need 23 regulatory prwtss, which does limit how many new lines can actually be built.
24 There is, noneth;I::ss, a very substantial amount of actual and potential entry.
25 As Mr. Tucker hu indicated, major transmission lines kre now under 26 construction and many additions are ir the planning stages.
In addition, i
n e ra-
J
.s Exhibit No.14 Page 33 1
nonutility proposals for transmission capacity are being put forward in the 2
WSCC. For example, in June 1987, a nonutility, Western Power, Inc., annour.ced i
3 the Southern Idaho Project.
The Southern Idaho Project is a proposal for a l
4 600-mile, 2,500-megawatt line transmission line from southern Idaho through 5
Nevada to the Las Vegas area.
Western Power's goal is to develop a 6
transmission system to deliver unregulated excess Northwest power to California, 7
Nevada, Arizona and New Mexico.
This proposal is discussed in greater detail 8
in Mr. Tucker's Schedule 11 of Exhibit 13 along with another proposed project.
9
'Q.
Has the transmission system within the WSCC region grown rapidly in 10 the past as well?
11 A.
Yes, it has, in 1977, there were approximately 77,000 transmission 12 circuit miles in place within the WSCC.
By 1982, the total was nearly 94,000 13 circuit miles.
By the beginning of 1987, there were over 104.000 circuit miles 14 in place, an increase of 36 percent from a decade earlier.
A disproportionate 15 share of the increase has been in lines of higher voltages.
16 Q. Have you reviewed the proposed wheeling policy for the merging 17 companies as described in the testimony of Mr. Topham?
18 A.
Yes.
19 Q. Does the proposed policy have any anticompetitive effect?
20 A.
No.
As I understand it, the proposed policy provides for access to 21 transmisss.on within the integrated areas of the merged utility, limited only by 22 the availability of capacity, on the basis of a FERC-filed transmission tariff.
It 23 provides for access to transmission, either firm or nonfirm, in other 24 circumstances as long as such access would have no adverse impact on the 25 reliability of the systems and would not result in uncompensated financial loss 26 to the ratepayers of the merged system.
This policy has a sound basis in nera'
~.
?**
Erhlblt No.14 Page 34 1
economics and provides noodiscriminatory access to whatever capacity is unused.
2 It also provides a mechanism for utilities with higher valued uses 103 obtain 3
access to lines that the merged entity is using by compensating it for its 4
opportunity costs (i.e., the estimated present value to the ratepayers of the use 5
that has to be curtailed to make capacity available).
6 In addidon to its general access policy, the merged companies will 7
provide nonfirm transmission service pursuant to both the Western Systems 8
Power Pool's experiment and the Intercompany Power Pool Agreement.
Since 9
UP&L is not presently a participant in the Western Systems' experiment, this 10 will add to bcth the generation and transmission available in that market 11 experiment.
12 There is nothing about the proposed wheeling policy that would make 13 access to the trassmission more restricted than it now is.
In fact, the 14 proposed polley would clarify, and niost likely enhance, the access to 15 transmission.
16 Q. Have you assessed the expected benefits or efficiencies associated 17 with the proposed merger?
18 A.
No.
The testimonies of Mr. Rodney M. Boucher and Mr. S: inberg j
19 outline the expected benefits from the proposed merger.
20 Q. Historically, UP&L has used purchases from the Northwest and salss 21 to the Southeast to use its transmission system to derive benefits for its rate-22 payers.
Would UP&L's merger with PP&L enhance the ability of the combined 23 utility to derive these benefits?
24 A.
No.
Economic theory predicts that the newly lategrated company will 25 function to buy from the lowest cost supplier at one end of the transmission 26 system and, when advantageous, sell to those willing to pay the most at the O e In*
6 i
yk
.s Erklbli No. N b
Page 35 1
other end of the trsasmission system.
This is exactly what UP&L now has the
[
2
' incentive and ability to do.
Therefore, the merger will not - result in the
[
l 3
lacreased ability or incentive of the combined utility to extract rents on behalf I
4 of its ratepayers based or, is strategic location.
[
F 5
Q. Are you troubled by the ability of UP&L and/or the merged entity to 6
derive benefits for its ratspayers through purchases arid resales?
7 A.
No.
As long as there is a substantial disparity between cost:, in the 8
Northwest and Southeast, there will be sales at whatever price the market will
\\
9 bear.
Absent enough capacity to bring in all the Northwest energy desired, 10 there will be econon.ic rents. I see es economic problems with allowing UP&L's 11 ratepayers, who tnre the costs and risks of building and operating the line, to l
12 realize those rents.
As long as the economically appropriate amount of energy 13 is flowing between the high-cost and low-cost areas, which power supplier 14 profits from the difference la not the main economic issue.
Moreover, the i
15 presence of high demand creates high opportunity costs for which the i
16 transmitting utility should be compensated and high return to transmission i
17 capacity provides the correct price signal to expand that capacity.
18 Q. Would the combined utility be able to charge higher prices for 19 Northwest energy than UP&L is able to charge now?
I 20 A.
No.
The merged entity has no more control over the transmission i
21 options available into the Arizona-New Mexico Power Area than UP&L presently 22 has.
23 Q. Would the combined utility have less incentive to purchase the least 24 expensive energy to replace its own energy for sale in the Arizona-New Mexico 25 Power Area?
I 26 A.
No.
As stated above, the combined utility has an incentive to j
n e ra' i
,AA 1
Erhlblt No.14 Page 36 1
minimize its joint costs associated with market sales.
Therefore, it is in its 2
interest to purchase the least expensive energy.
~
3 VI.
SUMMARY
OF ISSUES 4
Q. To conclude your testimony I will ask you to frame the results of 5
your analysis around the specific questions the FERC has asked be addressed in 6
this proceeding. First, what are the relevant markets involved?
7 A.
The relevant markets for evaluating the effect on ccmpetition of the 8
proposed merger are the retail and bulk power markets in which the merging 9
entities compete.
I have identified and annlyzed six markets in which the 10 merging entities historically have been substantial participants.
They are the retal: market, in which yardstick and !ndustrial loacation competition potentially 12 can take place, the bulk power markets in the four WSCC power areu and the 13 market for coal.
14 Q. Is the merger likely to lessen substantially actual or potential com-15 petition or create a monopoly in a relevant market?
16 A.
No.
My analysis indicates that the merger is not likely to 17 lessen substantially actual or potential competition or create a monopoly in any 18 relevant market.
19 The mersing utilities are adjacent to each other at only a few points 20 and are not significant remi! competitors.
To the extent they could be viewed 21 as retail competitors, it is only in industrial location or yardstick competition.
22 In either case, there exist many other actual or potential retail competitors in l
23 the region.
24 in the California bulk power market, the merging firms would have a I
25 relatively small market share of both sales and transmission access into this 26 market (8.4 percent of bulk power imports and 3.3 percent of transmission Ile Tn'
i;
.b 2.
Erklblt No.14 j
' Page 37 l
1 4
1 access).
Moreover, cogeneration, self-generation and potential competition from
(
4 2
other utilities and regions to supply California's future bulk power requirements l
]
3 is substantial.
(
i 4
The merging entities also have a relatively low bulk power and 5.
transmission market share in the Arizona-New Mexico Power Area (6.4 percent 6
of bulk power sales and 12.59 percent of transmission access).
This area has i
-7 relatively low internal generation costs and high projected reserve margins i
f 8
which reduces the significaosa of all outside sources.
i 9
Similarly, market shares for the Northwest Power Pool Area (10.8 10 percent of generation, 3,1 percent of bulk power sales and 20.05 percent of j
1 11 transmission access) and the Rocky Mountain Power Area (7.5 percent of bulk 12 power sales and 19.81 percent of transmission access) indicate that the merger 1
j 13 would not suostantially affect competition or create a monopoly.
[
1 14 Jinally, the merging parties have only a 6-percent share of 15 uncommlued coal reserves and much of their coal production is already 16 con;mitted to generation plants they own or participate in, j
17 Q. Art there significint barriers to entry in the relevant markets?
q 1
]
18 A.
No, While capital requirements, lead times and regulatory approval l
19 create barriers to entry, history demonstrates that they are not substantial i
t i
j 20 relative to the resources of firms in the region.
Entry is probably easier now l
21 than it has ever becc.
This is evidenced by the substantial amount of actual i
22 and potential entry by utilities as we!! as by nonutilities.
In the last 10 years, t
i 23 11ae miles of transmission capacity lo the WSCC area lacreased by 36 percent.
4 24 Over the same period, generation increased by about 40 percent.
These 25 compare with a load growth of about 30 percent.
Entry barriers are discussed i
l 26 further in Section V of my testimony, l
I j
ne Ta'
{
i
.I
s.
Ethlblt No.14 Page 33 1
Q. Will the merger result in an increase in concentration of economic 2
power and control by PacifiCorp Oregon of essential facilities?
3 A.
The merged entities do not control a significant share of transmission 4
facilities in or into any relevant bulk power market and the concentration of 5
ownership in such facilities would not increase materially as a result of the 6
merger.
In fact, my analysis indicates that the merged companies would control 7
at most about 20 percent of transfer capacity into any market.
3 In areas in which large transmission facilities are owned by one of 9
the merging entities, the merger does not increase market share.
The proposed 10 wheeling policy for the merging companies provides for access to transmission 11 as long as it does not adversely affect reliability or create an uncompensated 12 financial loss.
This policy is no more restrictive than the separate parties' 13 current access policy and will not create or increase the ability or incentives of 14 the combined utility to extract rents from any transmission t;aths currently owned or controlled.
16 Q. What alternative pathways exist from the Pacific Northwest to the 17 Southwestern United States?
18 A.
There are substantial alternative transmission paths into each relevant 19 market.
The transmission system connecting these systems is fully described in 20 Sections IVA through D of my testimony.
21 Q. Will PacifiCorp Oregon be able to foreclose competitors from access 22 to actual or potential competition within their service territories by virtue of 23 control over transmission?
24 A.
No.
PacifiCorp will have no more control over transmission to or 25 among markets than do the merging parties separately now.
As I have detailed 26 in Section !YA through D above, the merging parties control a small share of n e ra'
l I
. e.
Ex,hlblt No.14 Page 39 1
transmission capacity among markets.
This control does not increase as a result 2
of the merger.
The transmission policy of the merging companies would make 3
transmission available to other utilities under reasonable conditions.
4 Q. Will the merged company have facilities available for transmission of 5
power by its competitors?
6 A.
Yes. The proposed wheeling policy would not lessen and may enhance 7
interregional transmission access.
The proposed wheeling policy of the merged 8
company is discussed in Section V.
9 Q. Will the merged company control access to products such as coal used 10 to generate electricity and needed by competitors?
11 A.
No.
As fully discussed in Section IVG, the merged companies would 12 control less than 6 percent of the uncommitted coal reserves in the western 13 market and would be unable to restrict access to coal by competitors.
14 Q. Dr. Landon, does this conclude your testimony?
15 A.
Yes, it does.
16 n e I'n'