ML20153F783
| ML20153F783 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 02/24/1988 |
| From: | Landonj H UTAH POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML20153F598 | List: |
| References | |
| NUDOCS 8805110047 | |
| Download: ML20153F783 (67) | |
Text
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ig Exhibit B UNITED STATES OF AMERICA BEFORE THE NUCLEAR REGULATORY COMMISSION IN THE MATTER OF THE
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EXHIBIT B to Facility APPLICATION OF PACIFICORP
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Operating License No. NPF-1 FOR CONSENT TO THE TRANSFER )
Indemnity Agreement No. B-78 OF LICENSES
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REBUTTAL TESTIMONY OF JOHN H.
LANDON 8805110047'8GO509
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EXHIBIT NO. 213 NATIONAL FCONOMIC RE5EARCH AnOCI Ail $ INC 00%5t!LTING ECONOul5T5 Rebuttal Testimony l
of John H. Landon Senior Vice President National Economic Research Associates, Inc.
on behalf of UTAH POWER & LIGHT COMPANY PACIFICORP PC/UP&L MERGING CORPORATION Before the Federal Energy Regulatory Commission Docket No. EC83-2-000 February 24, 1988 1
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SUMMARY
OF REBUTTAL TESTIMONY OF JOHN H. LANDON ISSUES ADDRESSED I.
RELEVANT MARKETS Issue addressed by:
1.
Colorado River Enerav Distributors Association /American Public Power Association / National Rural Electric Coooerative Association /Public Power Council (CREDA et. al.) witness Gordon T. C. Taylor, Exhibit No.178, pages 13-17, 22-24, 27-28, 31-63 and 66-69.
2.
E.gggral Energy Regulatory Commissie 3 (FERC) Staff witness W. Russell Parter, Exhibit No. 99, pages 7.9 and 16-17.
3.
FERC.52Cf wi+. ness E. Allen Mosher, Exhibit No.100, page 6.
4.
Idahg_,,, Power Comoanv/ Montana Power Comesnv (IPC/MPC) witness Wi'liam R. Hughes, Exhibit No. 84, pages 16-20, 23, 27-28, 33-35, 65, 102, and Exhibit 85 (WHR-2).
5.
IPC/MPC witness Robert L. Miller, Exhibit No. 64, page 11.
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O y :s II.
CONTRACTUAL AGREEMENTS VERSUS MERGER Issue addressed by:
1.
Public Power Council / Northwest Public Power Association witness Lon L. Peters, Exhibit No. 36, pages 22-24.
2.
Nueor Steel witness Matthew !. Kahal, Exhibit No.18, pages 14-16.
3.
United Mine Workers of America et. al. witness Whitfield A.
Russell, Exhibit No. 20, pages 42-43.
4.
FERC Staff witness W. Russell Porter, Exhibit No. 99, pages 21-23.
5.
CREDA et. al. witness Randall P. Goff, Exhibit No,118, pages 4-5 and 7-9.
6.
IPC/MPC witness William R. Hughes, Exhibit No. 84, pages 23 and 85.
7.
CREDA et. al. witness Gordon T. C. Taylon, T.xhibit No.178, page 13.
III.
ALLEGED VERTICAL EFFECTS OF THE MERGER Issue addressed by:
1.
FERC Staff witness W. Russell Porter, r,xhibit No. 99, pages 9-13.
2.
Nucor Steel witness Matthew 1. Kahal, Exhibit No.18, pages 35-36.
3.
FERC Staff witness E. Allen Mosher, Exhibit No.100, pages 4-5.
4.
CREDA et. al. witness Gordon T. C. Taylor, Exhibit No. 178, pages 33 38.
5.
CREDA et. al. witness David T. Helsby, Exhibit No. 134, pages 23-24.
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IPC/MPC witness William R. Hughes, Exhibit No. 84, pages 21-24 57-59, and 102.
IV.
PREFERENCE FOR INTERNAL GENERATION AND REGULATORY EVASION Issue addressed by:
1.
IPC/MPC witness William R. Hur,hes, Exhibit No. 84, pages 25-26.
54-57 and 60-62.
2.
FERC Staff witness W. Russell Porter, Exhibit No. 99, pages 16-18.
VI.
RENTS ON GENERATION Issue addressed by:
1.
IPC/MPC witness William R. Hughes, Exhibit No. 84, pages 53, 60-65 and 84.
2.
FERC Staff witness W. Russell Porter, Exhibit No. 99, pages 14 and 17.
3.
IPC/MPC witness Robert L. Miller, Exhibit No. 64, page 21.
4.
fJEDA et.11. witness David T. Helsby, Exhibit No.134, page 24.
5.
IPC/MPC witness Lawrence A. Crowley, Exhibit No. 69, pager 18-19.
i Vit.
RETAIL COMPETITION issue addressed by:
1.
CREDA e t. al, witness Gordon T. C. Taylor, Exhibit No. 178, pages 18-19 and 21.
2.
Nucor Sted witness Matthew I. Kahal, Exhibit No.18, pages 33-34.
3.
CEfDA e t. at witness Thomas M. McCaffrey, Exhibit No.143, page 36.
Il e 1 11
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CONTENT AND CONCLUSIONS I. RELEVANT MARKETS l
Other witnesses have incorrectly defined specific transmission routes as separate markets.
An appropriate market should be defined from the buyer's perspective and include all of the reasonable alternatives to obtain bulk power.
i Those include internal generation and alternadve paths to remote generation.
The correct geogrrahic markets are the California-Southern Nevada Power Area, Arizona-New Mexico Power Area, the i
Rocky Mountain Power Area and tFa Nor' htvest Power Pool I
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Arca.
Each of these areas has distinct resources, different alternatives for bulk power and a different supply-demand balance.
There are also generally fewer transmission l
constraints within than there are between these areas.
11 O l'n'
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.' II. CONTRACT AGREEMENTS VERSUS MERGERS There are many well-recognized costs of achieving transactions through contract rather than within an integrated firm. These include:
(1) costs of negotiating contractual agreements among various parties that have different perceptions of the levels of risk and uncertainty; (2) costs of writins a compreher.sive contract that covers all current and future contingencies; (3) costs of monitoririg contractual performanec; and (4 costs of enforcing contractual promises.
The electric utility industry is characterized by uncertainty, complexity, asset specificity, sunk costs and infrequency of orders.
All of these make costs of contracting more significant.
The assumption that the merging parties could obtain the benefits of integration through contract are not well-founded, 11 O l' W
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l 111. ALLEGED VERTICAL EFFECTS OF THE MERGER Vertical restrictions are of concern only to the extent that they adversely impact horizontal markets.
Even assuming market power over transmission, the most likely effects of the merger would enhance competition and lower prices.
The better price signals within the merging firm (marginal cost) and the plan of the parties to increase sales to the South will both have the effect of enhancing competition.
This conclusion is consistent with economic theory, as is illustrated in three I
hypotheticals.
11 O l'n'
l-PREFERENCE FOR INTERNAL GENERATION AND REGULATORY EVASION Dr. Hughes' assertion that the merging companies would prefer internal generation to more economic external sources in order to evade FERC regulation is inconsistent with the facts.
To be true, his hypothesis requires that gli of the following assumptions be true:
(1) that UP&L has monopoly power as a seiler to the Southwest; (2) that FERC would have forced UP&L to stop engaging in buy / sell transactions; (3) that UP&L would have agreed to wheel as an alternative; (4) that FERC would have established wheeling rates based on some simple cost of servie9 t
formula; and (5) that state and federal regulators would have permitted the merged cempany to use high-cost internal generation when lower priced power was available from third parties.
The testimony explains why anat of these assumptions is likely to be true.
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V. RENTS ON GENERATION Monopoly rents derive from the restriction of output.
Economic rents derive from a difference between cost and the market-clearing price.
Northwest bulk power sellers derive economic rents for their access to low-cost generation sources.
Economic rent is also derived from rationing access to scarce transmission capacity.
As long as output is not restricted, economic rents are not economically objectionable.
The proposed merger would not result in monopoly rents.
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4-VI. RETAIL COMPETITION The merger will not have any signit'icant impact on retail
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The merging utilities are adjacent in only a few areas and have agreed to treat. utilities internal to their
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systems at least as favorably as they did before the merger.
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Exhibit No. 213 Page1 1
UTAll POWER AND LIGHT COh!PANY, PACIFICCORP 2
PC/UP&L h!ERGER CORPORATION 3
DOCKET NO. EC88-2-000 4
REBUTTAL TESTIh!ONY OF JOHN H. LANDON 6
Q. Are you the same John H. Landon who presented direct testimony in 7
this proceeding?
8 A.
Yes, I am.
9 Q. What is the puipose of your testimony in this proceeding?
10 A.
I am rebutting the testimony of certain intervenors and staff 11 witnesses regarding economic issues as follows:
12 I.
RELEVANTh!ARKETS 13 Issue addressed by:
14 1.
Colorado River Enerev Distributors Association /American Public 15 Power Association / National Rural Electric Coooerative 16 Associstion/Public Power Council (CREDA et. al.) witness Gordon 17 T. C. Taylor, Exhibit No.178, pages 13-17, 22-24, 2'l-28, 31-63 18 and 66-69.
19 2.
Federal Enerev Reculatory Commission (FERC) Staff witness 20 W. Russell Porter, Exhibit No. 99, pages 7-9 and 16-17, 21 3.
FERC Staff witness E. Allen hiosher, Exhibit No.100, page 6.
22 4.
Idaho Power Comosnv/hfontans Power Comosnv (IPC/MPC) 23 witness William R. Hughes, Exhibit No. 84, pages 16-20, 23, 27-24 28,33-35,65,102, and Exhibit 85 (WHR-2).
25 5.
IPC/MPC witness Robert L. hiiller, Exhibit No. 64, page 11.
26 n e l' R
Exhibit No. U2 Page 2 1
II.
CONTRACTUAL AGREEMENTS VERSUS MERGER 2
Issue addressed by:
3 1.
Eublic Power Council / Northwest Public Power Association witness 4
Lon L. Peters, Exhibit No. 36, pages 22-24.
5 2.
Nucor Steel witness Matthew I. Kahal, Exhibit No.18, pages 14-6 16.
7 3.
United Mine Workers of A merica et. al. witness Whitfield A.
8 Russell, Exhibit No. 20, pages 42-43, 9
4 FERC Staff witness W. Russell Porter, Exhibit No. 99, pages 21-10 23.
11 5.
CREDA et. al. witness Randall P. Goff, Exhibit No.118, pages 4-5 12 and 7-9.
I 13 6.
IPC/MPC witness William R. Hughes, Exhibit No. 84, pages 23 and 14 85.
15 7.
CREDA et. st. witness Gordon T. C. Taylor Exhibit No.178, page 16 13.
17 III.
ALLEGED VERTICAL EFFECTS C ' '1IE MERGER 18 Issue addressed by:
19 1.
FERC Staff witness W. Russell Porter, Exhibit No. 99, pages 9-13, 20 2.
Nucor Steel witness Matthew I. Kahal, Exhibit No.18, pages 35-21 36.
22 3.
FERC Staff witness E. Allen Mosher, Exhibit No.100, pages 4-5, 23 4.
CREDA et. al. witness Gordon T. C. Taylor, Exhibit No. 178, 24 pages 33-38.
l 25 5.
CREDA et. al. witness David T. Helsby, Exhibit No. 134, pages 26 23-24.
n e l' El t.
Exhibit No. 213 Page 3 1
6.
IPC/MPC witness William R. Hughes, Exhibit No. 84, pages 21-24 2
57-59, and 102.
3 IV.
PREFERENCE FOR INTERNAL GENERATION AND REGULATORY EVASION r
4 5
Issue addressed by:
6 7
1.
IPC/MPC witness William R. Hughes, Exhibit No. 84, pages 25-26.
8 54-57 and 60-62.
9 10 2.
FERC Staff witness W. Russell Porter, E.hibit No. 99, pages 16-11 18.
12 13 VI.
RENTS ON GENERATION 14 Issue addressed by:
15 1.
IPC/MPC witness William R. Hughes, Exhibit No. 84, pages 53, 16 60-65 and 84.
17 2.
FERC Staff witness W. Russell Porter, Exhibit No. 99, pages 14 18 and 17.
19 3.
IPC/MPC witness Robert L. Miller, Exhibit No. 64, page 21, 20 4.
CREDA et. at witness David T. H61sby, Exhibit No.134, page 24, 21 5.
IPC/MPC witness Lawrence A. Crowley, Exhibit No. 69, pages 18-22 19.
23 VII.
RETAIL COMPETITION 24 Issue addressed by:
25 1.
CREDA et. ?!. witness Gordon T, C. Taylor, Exhibit No. 178, 26 pages 18-19 and 21.
27 2.
Nucor Steel witness Matthew I. Kahal, Exhibit No.18, pages 33-j 28 34.
29 3.
CREDA et. al. witness Thomas M. McCaffrey, Exhibit No. 143, 30 page 36.
31 Il e l'IT
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Exhibit No. 213 Page 4 1
I.
RELEVANT MARKETS 2
Q. Dr. Landon, are you aware that some witnesses contend that the 3
relevant markets are different from those defined in your testimony?
4 A.
Yes.
Three witnesses suggest relevant geographic markets that are 5
different from the four regions I defined.
A fourth witness suggests that the 6
relevant geographic market is the area where the two merging compsnies are 7
interconnected.
A fifth witness defines both different product and geographic 4
8 markets.
A summary of these positions is as follows:
(1) Dr. Gordon T. C.
9 Taylor asserts, at page 16, lines 2-8, that the relevant geographic market for 10 bulk power is the general area covered by Western Systems Coordinating 11 Council (WSCC) member systems; (2) Dr. W. Russell Porter appears to suggest, 12 by a hypothetical at pages 7 to 8,
that individual transmission corridors 13 represent relevant product markets; (3) Mr. Robert L.
Mille,, at page 11, 14 indicates that the relevant geographic market for Montana Power is the 15 Southwest which includes both California and the Desert Southwest; (4) Mr. E.
16 Allen Mosher, at page 6, lines 2-6, asserts chat the relevant geographic market 17 is the area where Pacific Power and Light Company (PP&L) and Utah Power and 18 Light Company (UP&L) are interconnected; and (5) Dr. William R.
Hughes 19 asserts, at pages 16 to 17, that there are two sets of product markets:
20 transmission and bulk electricity.
The relevant geographic markets that Dr.
1 21 Hughes finds for transmission service are from the Northwest to California, 22 Southern Nevada and the Desert Southwest.
Dr. Hughes also finds that the 23 relevant geographic market for bulk electricity is the broad area of the WSCC.
24 He further asserts, at page 19, lines 19-20, without clarification, that the 25 "buying areas also correspond to areas identified by the Applicants...."
26 Q. What is the purpose of defining relevant markets in a merger 1
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Exhibit No. 213 Page 5 1
analysis?
2 A.
The purpose is to assess whether, or to what degree, the merger will 3
affect the ability of buyers to purchase in a competitive market.
4 Q. Have you reviewed the testimony of Dr. Hughes with respect to 5
transmission as a separate relevant market?
6 A.
Yes, I have.
7 Q.
Do you agree with his conclusions?
8 A.
No, I disagree with his conclusions.
9 Q. Please explain how your views differ from those of Dr. Hughes.
10 A.
In the fact circumstances of this proceeding, I disagree with both the 11 separation of transmission as a relevant market and with the specific markets 12 identified by Dr. Hughes.
Dr. Hughes has confused the elements of bulk power 13 sales that his clients need to maximize their net benefits with the markets
- .n 14 which they and others make transactions.
This confusion is especially evident 15 in his treatment of transmission.
As I will discuss in more detail below, 16 transmission issues which arise in this proceeding cannot be properly considered 17 without a simultaneous cor. sideration of the other elements of bulk power.
It is 18 the effect of the proposed merger on the degree of competition in bulk power 19 markets that should be at issue, not how the occasion of the merger can be 20 used to enhance the marketing ability of specific individual utilities.
21 Q. Please describe in more detail why, in your view, it is important not 22 to separate consideration of transmission from other aspects of bulk power 23 markets.
24 A.
Dr. Hughes, Dr. Porter and Dr. Taylor have created considerable 25 confusion regarding the proper method for defining relevant product and 26 geographic markets for antitrust purposes.
To define the relevant market n ei n
Exhibit No. 213 Page 6 1
properly, we must identify the competitive alternatives that ' buyers' have 2
available to them to satisfy their demand for particular types of goods and 3
services.
In this case, we have buyers who demand electric power for resale to 4
ultimate customers.
We should include in the relevant market all supply sources 5
that are or may be reasonably interchangeable substitutes for satisfying these 6
demands.
By identifying reasonable substitutes on the demand side and the 7
supply side, and the production and production capacity of the firms that are 8
supplying or would supply if prices rose slightly, we can then proceed to 9
determine whether a merger will have anticompetitive effects.
The primary 10 competitive concern is whether a merger will facilitate the exercise of market 11 power by sellers, making it possible for them to raise prices by restricting the 12 supply of the relevant product that is made available to buyers.
The exercise 13 of market power goes hand-in-hand with artificial supply restrictions, which in 14 turn lead to higher prices.
Mergers are only of concern from this perspective 15 if they lead to high levels of seller concentration and entry of new suppliers is 16 difficult.
17 Dr. Hughes, Dr. Porter and Dr. Taylor have turned the proper 18 approach to market definition on its head.
Rather than looking at the 19 substitute sources of supply available to buyers, they have looked at the effects 20 of the merger from the perspective of particular sellers.
Whether a specific 21 seller has alternative ways of getting his product to a market in which buyers 22 have many competing alternative sources of supply is irrelevant, both for 23 purposes of markat definition and for determining whether a merger will 24 adversely affect buyers.
The purpose of the antitrust laws is not to protect 25 specific competitors from incret. sed competition; it is to protect buyers from 26 higher prices resulting from the exercise of market power through a reduction n e r tr
Exhibli No. UJ, Page 7 1
in price competition.
2 In the case at hand, there are several substitutes available to buyers 3
to satisfy their demands for bulk power supplies.
They can generate for 4
themselves, buy from proximate interconnected utilities, or seek supplies from 5
more remote sources and use long-distance transmission capacity.
All of these 6
substitute supply sources are candidates for inclusion in the relevant market.
7 Separating, for purposes of economic analysis, sources and the associated 8
transmission capacity they rely on makes absolutely no economic sense.
9 Transmission into an area is less relevant the greater the number and 10 variety of proximate alternatives.
Thus, a particular transmission route into an 11 area is greatly reduced in importance if there are other routes which provide 12 adequate aaernatives to insure a competitive outcome.
One cannot determine 13 whether a merger reduces competition by focusing on whether specific firms or 14 methods of transportation are being used.
The public policy concern is with 15 the degree of competition in the market when all reasonable substitutes from 16 the buyers' perspective are considered.
17 An example will illustrate how inappropriate Dr. Hughes' approach is.
18 Let's assume that there is a buying area (Centerville) in the center of a large 19 geographical area which has no other buying areas.
See the figure on the next 20 page.
Located close to the buyers in Centerville are 10 equal-sized firms that 21 have the combined capacity to produce 1,000 units of a product that the buyers 22 in Centerville demand.
There are also four firms located at remote locations 23 which also produce for this market.
These firms are located North, South, East 24 and West of Centerville, and each has the espacity to produce 200 units of the 25 product.
Each remote producing area is connected to Centerville by a railroad 26 that has exactly 100 units of capacity. Consumers in Centerville are currently Il e 1 iT
Denterville Exam 3:.e O
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100 units
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Exhibit No. 213 i
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consuming 1,000 units per year made up of 400 units of imports and 600 units 2
of local production.
3 According to Dr. Hughes' origin / destination approach, each of the 4
railroad lines would be a relevant market.
Local procluction would not be 5
considered at all.
And, according to his approach, the owner of each rail line 6
would have a monopoly over each of these very narrowly defined markets. This r
7 approach cannot possibly make sense.
Telling us that one of the remote 8
suppliers has 100 percent of some transportation linkage tells us nothing of 9
interest here about market power or collusion from the perspective of the 1
10 buyers.
We have to go back to the buying market and look at the alternative 11 supply sources that buyers have available to them and then look at the number, 12 size and distribution of supply sources.
13 There are 1,800 units of capacity available to serve this market 14 owned by 14 different firms.
From the buyer's point of view, this is a very i
15 competitive market.
If each firm now serving the market has 10 percent of 16 thesales to the market, the HHI is 1,000.
The competition among the local 17 producers necessarily places a cap on what any remote supplier or the remote 18 suppliers as a group can charge.
The competitiveness of the market and the 19 power that a single remote supplier may have to influence prices paid by buyers 20 cannot be determined without looking at the characteristics of all of the supply i
21 alternatives the buyers have available to them.
22 Q.
P! ease describe the change in the analysis if we assume that there 23 are two alternative sellers (A and B) at the Northern remote location, each 24 having 100 units of capacity, and that one of these sellers controls the railroad l
25 from the North into Centerville.
26 A. In the figure on the page that follows, I have adcted the two l
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Exhibit No. 213 Page 11 1
Northern alternative sellers, A and B.
Let us assume that A controls the
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Even with the assumed railroad monopoly from the North, A must
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Centerville.
The ability of A to influence the price Centerville pays is very
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5 slight, if any, because we have hypothesized a very competitive market.
In this 6
respect, the market is unchanged from the first example.
What has changed is efy 7
the ability of one potential seller (A) to block access to another potential seller 8
(B). The following are possible alternatives:
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The market price in Centerville is so low that neither A nor B
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In this instance, the control of the
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The market price la Centerville exceeds the production cost of
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14 either A or B, but not both.
In this instance, A will sell its C
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The control over the J
17 transmission link may affect the allocation of economic rents
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The market price in Centerville greatly exceeds the cost of 20 production of both A and B.
In this case, A will make the N.E
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24 lowest cost supplier.
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each other.
2 The critical conclusion from this example is the necer,sity to assess 3
all of the alternatives available to buyers in Centerville before we can draw any 4
conclusions with respect to the market power of any participant.
Where there 5
are many alternatives--a competitive market--efficiency is achieved despite A's 6
absolute control of the railroad from the North.
7 Q. Please discuss how this principal applies to your California Southern 8
Nevada Market.
9 A.
Dr. Hughes defines the transmission routes to California as a 10 relevant market, dismisses the Bonneville Power Administration (BPA) and 11 Pacific Gas and Electric Company portions as not giving his clients the type 12 and degree of access to California they desire, and then concludes that the 13 transmission systems of the merged companies are the only alternatives, ne 14 correct upproach is to examine the power supply alternatives available to 15 utilities ' in California.
In addition to the transmission ties to the Northwest, 16 the alternatives include internal generation, cogeneration and significant 17 transmission routes to the East.
Moreover, the assessment of Northwest 18 alternatives must include BPA and all of the other significant actual and 19 potential bulk power suppliers in the region.
Again, the appropriate focus of a 20 competitive analysis is on the process of competition as it affects buyers, not 21 on the alternatives of specific sellers.
22 Dr. Hughes appears to recognize that competition between utilities 23 serving the bulk power market is more pervasive than his almplistic and 24 inappropriate transmission route analysis takes into account.
In response to 25 PP&L and UP&L's Second Discovery Request to Idaho Power Company (IPC) and l
l 26 Montana Power Company (MPC) No. 84, included as Schedule 1 of Exhibit 214, l
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Exhibit No. 213 Page 13 1
Dr. Hughes acknowledges that:
"The bulk electricity market area, WSCC, 2
includes competition in bulk electricity sales to the Desert Southwest from 3
areas other than the Northwest."
4 Q. Do you have the same type of concern with respect to the definition 5
of transmission from the Northwest to the Desert Southwest as a separate 6
market?
7 A.
Yes, I do.
As I indicated in my direct testimony, the Desert 8
Southwest has internal generation resources in excess of current needs and is 9
interconnected to the Rocky Mountus area and to California, as well as to the 10 Northwest.
The economic significance of a specific route to the Northwest 11 must be considered in the context of all power supply alternatives available to 12 buyers in the Southwest.
13 Q. Please discuss Dr. Hughes' suggestion on pages 27, 33 and 34 that 14 transmission to Southern Nevada should be viewed as another relevant market.
15 A.
This transmission path is not a market for the same reasons as cited 16 previously in reference to Dr. Hughes' other asserted transmission markets.
17 Internal resources in the Southern Nevada area, plus strong ties with other 18 areas, provide substantial alternatives to the purchase of Northwest energy.
19 Furthermore, all Northwest sources of power must be considered in evaluating 20 the competitive supply alternatives available to buyers.
In addition, Southern 21 Nevada is much smaller than any of the other markets Dr. Hughes suggests; and 22 it is the only one to split a single WSCC region.
Dr. Hughes does not provide 23 a detailed explanation for this choice.
This does not appear to represent a 24 logical market area within which to p.ssess the merger.
25 Q.
Do you agree with Dr. Hughes that the proper focus in this 26 proceeding is on vertical problems?
n e rn'
Exhibli No. 213 Page 14 i
1 A.
No.
Dr. Hughes' statements, at page 102, that these are "vertical" i
2 problems and that I incorrectly look at
- horizontal
- competition are confused.
3 It is well recognized that vertical integration or vertical restraints create 4
competitive problems only by reducing competition at some horizontal level of 5
the production chain (facilitate collusion or exclusion).
This is recognized by 6
the U.S. Department of Justice's (DOJ's) Guidelines for Vertical Restraint.
A 7
copy of the guidelines, including the summary that accompanied them, appears 8
as Exhibit 214, Schedule 2.
The summary, at page xi and continuing onto page 9
xii, states that:
10 The Guidelines summarize the most prominent i
11 procompetitive and anticompetitive uses for vertical 12 restraints.
On the procompetitive side of the ledger, 13 vertical restraints may lower distribution costs, facilitate i
14 the entry of new producers into a market, insure the 15 provision of pre-sale demonstration and other informational 16 services, allow a supplier to protect its investment in 17 services to dealers, and permit firms to allocate risks or 18 costs in an efficient manner.
Vertical restraints also can 19 improve product quality and safety and teduce transactions 4
20 costs in numerous circumstances.
21 22 On the anticompetitive side of the
- ledger, vertical 23 restraints may be used to facilitate price
- fixing among i
24 competing suppliers or among competing dealers.
Vertical i
25 restraints can also be used to exclude rivals from the 26 market.
These undesirable anticompetitive effects are, 27 however, only likely in relatively concentrated markets--
28 markets characterized by relatively few competitors--
29 where the restraint is used by firms representing a large 30 percentage of the market.
31 32 The Guidelines do not apply to regulated industries.
Such 1
33 industries may be subject to competitive distortions that i
34 alter the normal economic effects of vertical restraints.
l 35 36 Q. The last paragraph you quoted indicates that the guidelines do not i
37 apply to regulated industries.
Does that make both Dr. Hughes' point and your f
I 38 response irrelevant to the question of the proposed merger between PP&L and i
39 UP&L7 l
D 13 l'D'
_. _. _, J
Exhibit No. 213 Page 15 i
A.
No, it does not.
Among the buyers and sellers in the bulk power 2
market, the relations are largely voluntary and negotiated.
That means that 3
there is generally a competitive situation in which regulation plays a limited 4
role.
The fact of regulation would make it desirable to focus on vertical issues 5
only if regulatory evasion were a serious concern.
In Section V below, I 6
discuss why that is not the case.
7 Q. Do the DOJ Merger Guidelines also indicate that market power is 8
found not in vertical restraints but at some horizontal level?
9 A.
Yes, they do.
(The DOJ Merger Guidelines are included as Schedule 10 20 of Exhibit No. 15).
Except in the special case of regulatory evasion, the 11 Merger Guidelines at e concerned with the effect on competition at some 12 horizontal level.
The competitive problems associated with vertical mergers are 13 discussed in Section 4.2, pages 42 to 50.
Competitive problems of vertical 14 mergers are discussed in terms of the likely effects of barriers to entry, 15 facilitation of collusion and the evasion of rate regulation.
The following 16 quotes indicate the concerns within the guidelines regarding the effect on 17 competition:
18 Barriers to entry are unlikely to affect performance if the 19 structure of the primary market is otherwise not conducive 20 to monopolization or collusion. [Section 4.213, page 46.]
21 22 After the merger, the utility would be selling to itself and 23 might be able arbitrarily to inflate the prices of internal 24 transactions.
...The Department will consider challenging 25 mergers that create substantial opportunities for such 26 abuses. [Section 4.23, page 49.]
27 Note that the term "primary market' referes to the market in which 28 the competative concerns are being evaluated.
29 Q.
Evasion of regulation does not necessarily occur at a specific 30 horizontal level.
Do Dr. Hughes' concerns with regulatory evasion suggest that n e T R*
a, e
Exhibit No. 213 g*
Page 16 1
market power in vertical, rather than horizontal levels?
2 A.
No.
The problem of regulatory evasion is, as I ladicated, a special 3
case which I discuss below.
Both the Merger Guidelines and the Vertical 4
Restraint guidelines call for estimating Herfindahl-Hirschman Indices (HHIs) at 5
both levels of the vertical chain, just as I have done in my direct testimony.
6 In the end, the only
- vertical" argument that Dr. Hughes has is a ' foreclosure
- 7 argument that relies on an assumption that the purpose of the merger is to 8
evade Federal Energy Regulatory Commission (FERC) transmission rate 9
regulation through vertical integration, if this assumption is incorrect, all of 10 Dr. Hughes' arguments that the merger will lead to higher costs and prices fall 11 apart completely.
The issues of whether the merged firm would choose high-12 cost generation if lower priced off-system purchases were available and the 13 broad issue of regulatory evasion are discussed in Section IV of this testimony, 14 Even if Dr. Hughes' regulatory evasion argument were correct, a 15 foreclosure would be a significant problem downstream only if the suppliers in 16 the market that depend on the vertical chain are a large fraction of the 17 competing suppliers in the market.
This is true since the exercise of monopoly 18 power goes hand-in-hand with restrictions in the quantity of the product made 19 available to the market.
This is clearly not the case here.
Neither IPC nor 20 MPC made any sales into the Southern Nevada or Desert Southwest areas during 21 either 1985 or 1986, the most recent periods for which the information is 22 publicly available.
I have included copies of the relevant sections of the FERC 23 Form I reports of IPC and MPC as Schedule 3 of Exhibit 214.
Furthermore, 24 the merged company plans to increase transactions to the Southwest, not 25 restrict them, increased sales into a market implies lower prices, not monopoly 26 behavior.
11 O T'Y
Exhibit No. 213 Page 17 1
Q. How can the effect of PP&L and UP&L on buying markets be 2
evaluated?
3 A.
We can evaluate PP&L and UP&L's effects on the prices that will be 4
d.orged in buying markets only by examining their market position in the 5
context of the substitutes available to buyers to serve their power needs.
6 Buyers have no inherent demand for transmission.
As I have noted above, 7
Dr. Hughes' market definition excludes from consideration all substitutes using 8
alternative transmission routes, coming from other regions or generated locally.
9 This is an inappropriate way to define a market in general, and it is especially 10 inappropriate in this case since there is not enough transmission capacity 11 controlled by the merging firms to supply more than a small fraction of the 12 demands in relevant buying markets, some of which have excess capacity (and 3
13 have stopped buying large quantitles from the Northwest--and at today's low 14 prices--because local substitutes are cheaper).
15 Even if the merged entity controls 600 megawatts of transmission 16 capacity between the Northwest and the Southwest, this represents only a small 17 fraction of the supply alternatives to which buyers can turn.
Local generation 18 in the Southwest is clearly a good substitute for purchased power from the
]
19 Northwest.
There is abundant low-cost generating capacity in the Southwest.
20 When oil and gas prices fell in 1986, reducing the cost of generation in 21 California, transaction prices for Northwestern power fell considerably, 22 reflecting the substitution possibilities among supply sources in these regions.
23 At the current level of oil prices and capacity, some capacity in the Northwest 24 is a glut on the market because there are good substitutes for it.
Exhibit 214, l
25 Schedule 4 shows that total utilization of the Pacific Intertie has fallen in 26 recent years from over 90 percent in 1984 to barely above 70 percent in 1986.
t n e r a-
+.
Erhlblt No. 213 Page IS I
Furthermore, if economic conditions change, the only evidence that would be 2
convincing regarding UP&L's alleged market power would be evidence that it i
3 restricted the quantity of transmission (buy / sell) made available in the market.
4 Q. Is Dr. Hughes' oil pipeline analogy which he discusses at pages 24 to 5
28 appropriate?
6 A.
No.
It is important to recognize that in most pipeline markets, the 7
buying region does not produce oil, it must buy the oil from a remote location.
8 The only way that the buyers can get oil at all is to transport it long 9
distances.
If there were locally produced oil, one would certainly include that 10 oil in the relevant market and not ignore it by isolating transportation as a 11 separate product.
It would make sense to focus on a specific transportation 12 service as a separate product if there were no alternative supply sources to 13 which buyers could turn, but one could sensibly come to this conclusion only
{
14 after a careful evaluation of the supply alternatives faced by the buyer, if 1
15 barge or truck transportation provided equivalent transportation
- service, 16 products supplied using these transport modes should be included in the market 17 as well.
If the product were to come from diverse locations, the products j
18 produced in all of these locations would be in the market.
Dr. Hughes' 19 suggested markets do not include alternatives internal to the market area, such j
20 as generation from utility-owned resources or from cogeneration.
Dr. Hughes' 21 primary error is to look at this from the viewpoint of two specific sellers j
j 22 rather than from the viewpoint of buyers.
This is particularly strange in this 23 case because in 1985 and 1986 IPC and MPC made no significant sales to the 24 Southwest at all.
The merger will not foreclose them from a market in which 25 they have not effectively participated.
26 Q. At pages 27 to 28 of his testimony, Dr. Hughes cites a 1984 DOJ 1
11 e l'n' I
l
Exhlblt No. 213 Page 19 1
study in support of his analysis of the transmission market.
Do you have any 2
comments on its relevance?
3 A.
Yes.
Dr. Hughes states, on page 27, that the concepts used in 4
analyzing transportation markets in other industries are useful in defining 5
transmission markets.
In particular, he cites a preliminary report by the DOJ 6
assessing the degree of pipeline market power (see Exhibit 85, (WRH-2)) and 7
claims that the feamework med in this analysis is applicable.
As stated in that 8
report, however, this study addresses the competition faced specifically by oil 9
pipelines, rathet than competition in the petroleum market generally and does 10 not attempt to account for potential entry of new pipelines or refineries or 11 competition from alternative fuels.
12 The basic principles used by the DOJ to define markets are specified 13 in the DOJ's Merger Guidelines.
The principles governing the definition of a 14 market are based on buyer (seller) response to an increase (decrease) in price.
15 Specifically, The Department will begin with each product 16 (narrowly defined) produced or sold by each merging firm 17 and assk what would happen if a hypothetical monopolist of 18 that product imposed, a "small but significant and 19 nontransitory" increase in price.
If the price increase 20 would cause so many buyers to shift to other products that 21 a hypothetical monopolist would not find it profitable to 22 impose such an increue in price, then the Department will 23 add to the product group the product that is the nett-best 24 substitute for the merging firm's product and ask the same 25 question again.
This process will continue until a group of 26 products is identified for which a hypothetical monopolist 27 could profitably impose a 'small but significant and 28 nontransitory increase in price.
... In general, the price 29 for which an increase will be postulated will be whatever 30 is considered to be the price of the product at the stage 31 of the industry being examined.
(footnotes omitted.
U.S.
32 Department of Justice, Merner Guidelines, as of June 14, 33 1984, pages 6-7, included as Exhibit No.15, Schedule 20.]
34 Viewing transmission separately under these guidelines makes no sense.
It is 35 the products that the merging firm's customers view as substitutes which define 11 e 2 ir
r Exhibit No. 213
{
Page 20 t
j i
the market under the DOJ's Merger Guidelines.
In this case, the customers are l
)
2 buyers of bulk power in California and the Arizona-New Mexico area, and it is' 3
3 the price of bulk power to these customers which is at issue.
[
t 1
4 Q. Have you reviewed Dr. Porter's example, at page 7, which purports to i
5 demonstrate why transmission should be a separate market?
6 A.
Yes, I have.
7 Q. Does his example demonstrate that transmission links taust be 4
8 considered separate markets.
r 9
A.
No, it does not.
l 1
10 Q. Please explain.
11 A.
In his example, the buyers are located at point A.
The transmission I
1 l
q 12 lines make it possible for them to purchase power from B or C or both of 1-13 them.
E and C are clearly substitutes from the buyer's perspective.
They
[
1 14 should both be in the market.
If B and C merged, then we would have a j
15 monopoly rather than a duopoly.
My method of computing market shares would 16 pick this up quite properly.
The fact that B cannot move power directly to C i
37 is irrelevant.
Adding such a link would not increase the number of purchasers 18 to which A can obtain access.
The power available from B and C are the
{
19 substitutes, not the transmission lines themselves.
Looking at the substitution 20 between transmission lines tells you nothing about the market power that the i
1 l
21 suppliers at the end of the lines have.
If we add two more remote sellers at 22 different points in space, each with its own line, we would increase substitution i
I, l
23 possibilities even more by giving the buyer two more supply options.
{
24 Dr. Porter's approach would tell us that we have created two more monopolies 25 because the transmission lines are not "substitutes."
This is clearly incorrect.
l 26 It becomes even more incorrect when we realize that if we added i
n e vn-i
Exhibli No. 213 Page 21 I
suppliers at A (local), Dr. Porter's method would exclude them from the market.
2 Thus, his appro2ch tells us to create a market that includes only remote 3
suppliers and treats them each as a monopoly even though the transmission 4
network he has assumed makes them substitutes from the buyer's perspective.
5 This is just the opposite of how we normally define geographic markets.
He 4
6 seems to be confused between the ability of suppliers to sell to one another 7
and substitution possibilities from the perspective of the buyer.
Pepsi does not 8
have to buy from Coke to put them both in the market.
If we are interested 9
in competition in the shoe market in New England, we do not exclude New 10 England production and look only at the shoes that Conrail delivers from the 11 South.
The basic problem here is that the product has been defined incorrectly 12 again. The product relevant to this merger is electric power.
13 Q. At pages !! to 14 of Dr. Porter's testimony, he uses examples which 14 purport to show the weaknesses of your analysis in ignoring local transmission 15 concentration. Does it do so?
16 A.
No.
All of these examples ignore the ability of the buying market 17 (i.e., California) to generate power itself or to purchase from QFs or from the 18 Southwest.
They also ignore the fact that there is plenty of espacity in the 19 Southwest.
UP&L is selling in the Southwest economy market ihr prices 20 ranging from about 1.5 to 2.5 cents per kilowatt-hour today.
There jet is not 21 any significant market power to be exercised at prices in this range, for supply 22 is very elastic.
23 Q. Is Dr. Porter's numerical example which starts at page 16 on point?
24 A.
No.
This numerical example demonstrates that in order to exercise 25 monopoly power one must restrict supply.
Since the merged company plans to 26 increase sales over its transmission interconnections, it would act exactly 11 O l'n'
y Eg%Ibli No. 213 Page 22 l
1 opposite to what a monopolist would do.
Since the merged company plans to 2
increase supply, prices will fall in the buying market.
3 Q. In summary, then, do you agree with Dr. Porter's conclusion that the 4
merger could result in increased psices for power because of the merged party's j
)
5 controls over transmission lines?
6 A.
No, I do not agree.
J 7
Q. Would defining transmission and bulk power sales as distinct product 8
markets change your view as to the merger's effects on market power and bulk 9
power supply costs in the purchasing areas which Dr. Hughes and Dr. Porter 10 have alleged?
11 A.
No.
Even if viewed as separate markets, there is nothing to indicate 12 that the merger would have a negative effect on the availability of competi-13 tively priced bulk power supplits or significantly increase the control over sales 14 or transmission to any of the purchasing areas.
As I have indicated in my i
15 direct testimony, UP&L has no firm access transmission to the California market l
16 and the PP&L entitlement is about 3.3 percent of the total transmission capacity l
17 into California.
The merger will not increase the concentration or the total 18 control of PP&L and UP&L over access to this area.
Concentration of f
19 transmission access to the Arizona-New Mexico area would not increase since i
20 PP&L does not control any transmission access to that area.
The combined 21 market share of the merging entities would not increase beyond that currently t
i 22 held by UP&L.
Thus, even considering transportation as s separate market.
[
t 23 control over transmission access to purchasing areas does not increase.
l 24 Nor would the merger have much effect on concentration of bulk 25 power sales into the buying areas.
For example, concentration, as measured by i
26 the HHI for total sales in 1986 to California's leading utilities, would change by n e ra'
Eshlblt No. H3 Page 23 1
only 27 points and the index for bulk power sales to the Arizona-New Mexico 2
utilities would be unaffected as a result of the merger.
This is shown in 3
Schedules 17 and 26 to my direct testimon; (Exhibit No.15).
4 Q.
Dr. Landon, have you reviewed Dr. Taylor's tudmony starting at 5
page 31 on the subject of tran1 mission in the bulk power market?
6 A.
Yes, I have.
I found his testimony on this point very hard to follow.
7 Dr. Taylor first asserts that the bulk power market consists of the whole WSCC 8
region.
My testimony discusses this contention below.
He goes on to discuss 9
the idea that transmission lines are essential facilities.
This seems to lead him 10 to the consideration of transmission as a separate product and market, just as 11 do Dr. Hughes and Dr. Porter.
My conclusion with respect to Dr. Taylor's 12 argument on this point is the same as with the others, it is the alternatives 13 that buyers face that determine the state of the market, not the control of any 14 one or any set of transmission lines.
15 Q.
Dr. Taylor presents on pages 38, 48, 52 and 57 a series of four case 16 studies which use the notion of a
market based on transmission 17 origin / destination links.
As part of his market analysis for the four cases he 18 uses HHis.
Does Dr. Taylor's market analyses of the four cases aid this 19 Commission in determining whether the merger of PP&L and UP&L is in the 20 public interest?
21 A.
No.
First, Dr. Taylor's analyses which imply transmission as a 22 separate market are subject to the same problems as are Dr.
Hughes' 23 transmission markets.
The same criticisms apply.
Second, Dr. Taylor's use of 24 HHIs is not meaningful.
His HHis:
(1) are not made for the product and 25 geographic markets that he has defined; (2) are based on internally 26 inconsistently developed market shares; and (3) use a misleading idea of control 110 Un*
Erhlblt No. 213 Page 24 1
of access to transmission, j
2 Q. Dr. Taylor uses his four cases in an attempt to argue that the 4
3 merged utilities would have market power which would have an anticompetitive 4
effect. Do his four cases provide support for his argument?
5 A.
No.
His argument is self-defeating.
At page 36, line 26 through 6
page 37, line 6, Dr. Taylor argues:
7 Increased brokering is a primary goal that PacifiCorp plans to 8
achieve through the purchase of Utah Power's transmission 9
system.
This exercise of market power over transmission, if 10
- allowed, will be anticompetitive in its
- effect, because 11 PacifiCorp will buy at a price below the market price, 1
12 weakening its rivals not by greater efficiency but by 13 forecto:ing them from the market.
e 14 Close examination of Dr. Taylor's argument shows that it is self-15 defeating.
Dr. Taylor argues that the merged utilities will inerene the use cf 16 the UP&L transmission system and that tl.at is anticompetitive.
This position f
17 is not logical.
If the merged utilities innease the use of UP&L's transmission 18 system and provide more bulk power siternatives to the Desert Southwest and 19 the California-Southern Nevada markets than currently is available, they are:
20 (1) increasing supplies in the market and enhancing competition, not restricting 21 alternatives and exercising market power; and (2) using the UP&L transmission 22 system more efficiently than it is currently being used, increasing overall 23 efficiency.
Dr. Taylor's argument is an argument in favor of the merger and t
24 not against, as he proclaims.
3 25 Dr. Taylor's argument that the merged t.tilities will buy below market 26 price and foreclose rivals from the market also does not stand close 27 examination, if the merged utilities are increasing the use of the UP&L I
28 transmission s s te m to make bulk power sales to the Desert Southwest and 29 California-Southern Nevada
- markets, there must be increased generation i
1 i
nern-l
Exhibit No. 213 k
Page 25 I
upstream of the UP&L transmission system.
Increased generation must come 2
from the merging parties or from other Northwest utilities.
Increased I
i i
3 generation will come forth only in response to a price that covers marginal 4
costs.
I have explained elsewhere in my testimony why the merged utilities 5
would not logically favor their own generation, unless their own generation had f
6 a lower marginal cost than the price charged by other utilities.
As I have 7
argued elsewhere in this testimony, the result of the merged utilities desire to 8
increase bulk power sales to the Desert Southwest and California-Southern 9
Nevada; together with the better price signals between the merging firms i
10 (marginal cost) may result in more price competition among suppliers in the J
l 11 Northwest, and a market price closer to marginal cost than now exists.
If that i
12 occurs, and it is one of Dr. Taylor's fears, it will enhance economic efficiency l
13 and competition, not be anticompetitive, as Dr. Taylor claims, i
i j
14 Q. Dr. Landon, you indicated that Dr. Taylor's use of HHis was not l
15 meaningful and provided three reasons.
The first reason was that the HHis 16 that Dr. Taylor calculates are not relevant to the markets he defines.
Why are l
17 Dr. Taylor's HHis not relevant to the product and geographic markets that he t
18 defines?
19 A.
Dr. Taylor agrees with me at page 22 that bulk power is the 20 relevant product market, but he develops his HHis not for bulk power but l
l 21 rather elements of transmission.
In addition, while Dr. Taylor claims that the i
i i
22 whole WSCC is the relevant geographic market, he develops his HHis for 23 particular origin / destination routes.
This approach ignores power supply i
24 substitution opportunities and is inconsistent with the entire WSCC being the i
)
25 relevant geographic market.
The idea behind defining relevant product and 1
26 geographic markets is to establish products and areas where they are traded i
l n e Un*
Exhibit No. 213 Page 26 I
which are useful for competitive analysu.
If Dr. Taylor is serious when he 2
testifies that bulk power is the relevant product market and that the entire 3
WSCC is the relevant geographic market, then he should be calculating his HHis 4
for bulk power transactions for the entire WSCC, He does not do this.
5 Q. The second reason that you gave for the lack of meaning of 6
Dr. Taylor's HHis was that the market shares underlying his calculations are 7
Internally inconsistent.
How are the market s.', ares underlying Dr. Taylor's HHis 8
internally inconsistent?
9 A.
Dr. Taylor's inconsistencies in developing his notion of control over 10 transmission links are detailed in the rebuttal testimony of hir. James 11 D. Tucker.
Mr. Tucker shows that Dr. Taylor's HHis are based on two 12 inconsistent standards for the level of control over transmission links:
(1) a 13 standard which takes into consideration the constraints and firm obligations of 14 transmission links he assigns to parties other than PP&L and UP&L; and (2) a 15 standard for the links which he assigns control to PP&L and UP&L which do 16 not take these constraints and obligations into acco nt.
This double standard 17 artificially inflates both the pre-merger HHI and the increase in the HHI d'!t to 18 the merger.
19 Q. The third reason that you provided for the !ack of meaning for Dr.
20 Taylor's HHis is that he uses a misleading idea of control over access tc 21 transmission.
How is Dr. Taylor's idea of contrcl of access to transmission 22 misleading in assigning market shares when calculating his HHis?
23 A.
In all four cases Dr. Taylor uses the notion that if PP&L or UP&L 24 controls a single element in a particular transmission origin / destination route, 25 then it has control over the entire route.
This idea is attractive, but it is 26 overly simplistic and does not provide information upon which this Commission 11 O l'n'
1
[*
Exhibit No. 213 Page 27 I
can make informed decisions about the public interest.
This can be seen by an 2
- example, if a transmission route between X and Y has three links A, B and C, 3
each owned by a separate owner, assigning sole control to that the transmission 4
route to the owner of link B is overly simplistic, as the route is equally 5
controlled by the owners of links A and C.
Effective control over the 6
transmission route is indeterminate and subject to the agreement of all three 7
parties.
To the extent utilities other than PP&L and UP&L "control" elements 8
in any transmission origin / destination route, they have as much control over 9
that route as does PP&L or UP&L.
10 The difficulties inherent in assessing the choice of individual origins 11 and destinations of transmission routes, and the difficulties of establishing who 12 controls these routes, illustrate why transmission market 3 are not particularly 13 useful in examining bulk power alternatives.
The interaction of internal 14 generation and its close substitutes, which make up a true market for bulk 15 power, can be properly evaluated through the use of HHis based on all 16 reasonable alternatives.
This is what I have done in my direct testimony, it is 17 not what Dr. Taylor has done with his ill-considered and inconsistently applied 18 HHis for transmission origin / destination routes.
l 19 Q.
Dr. Taylor states at page 66 that the barriers to entry in building 20 transmission lines are much higher than is indicated in your direct testimony.
21 Do you have a comment on that point and its importance?
22 A.
Yes, I do.
It is not my intent to imply that there are no difficulties 23 in building transmission lines.
Hurdles or impediments to entry do not have to l
24 be absent in order to conclude that entry can occur.
Dr. Taylor indicates at 25 pages 66 to 65 that economies of scale, the necessity of joint coordination, high 1
l 26 absolute costs, attempted foreclosure by other utilities that already have lines i
l i
lle UR*
Exhibit No. 213 Page 28 1
in place, the need to cross the service territories of other utilities, the need to 2
cross federal lands and the policies and actions of the BPA are all barriers to 3
entry.
Each of these factors can be viewed as difficulties entrants must face, 4
but not as factors that disadvantage entrants relative to established firms.
5 Potential builders do not face difficulties in the construction of new lines that 6
were not faced by the builders of existing lines.
Planners have overcome these 7
difficulties in the past and are continuing to do so at the present time as new 8
projects are conceived, planned and completed.
My direct testimony indicated 9
that the number of transmission circuit miles in place in the WSCC increased by 10 36 percent over the decade from 1977 to 1987 (Exhibit 14, page 33).
11 Mr. Tucker's direct testimony (Exhibit 12, pages 38 to 43) discussed the status 12 of several near-term projects.
Given the projected demand growth in the 13 WSCC, there is no reason to believs that projects that will deliver economic 14 benefits that exceed costs will not continue to be built in the future.
15 Q.
Dr. Taylor points out, on page 69 of his testimony, that the Merger 16 Guidelines refer to a time standard of one year for analysis of entry.
Is this 17 correct?
18 A.
No, it is not correct. A copy of the, Merger Guidelines is included as 19 Schedule 20 of my Exhibit 15.
On page 28 of these guidelines, it states that a 20 two-year time period is appropriate for analyzing entry conditions.
A one-year 21 time period is the requiremen: for inclusion in the market itself.
The market 22 concentration measures included in my direct testimony do not include future 23 transmission projects or future developments of any kind.
24 Q
Dr. Landon, do you think that two years is a long enough time period 25 for an entry standard in this industry?
26 A.
No, I do not think it is long enough.
In nearly all aspects of the n e ra-
0 Exhibit No. 213 o,
Page 29 1
electric utility industry, there are lead times required for negotiating, planning 2
and constructing facilities.
A realistic entry standard must recognize these 3
realities.
For many major transmission projects 3 to 5 years would be more 4
appropriate than a two year standard.
5 Q. Dr. Landon, Dr. Taylor states at page 16 that the relevant geographic 6
market for bulk power is the whole crea covered by the WSCC. Do you agree?
7 A.
No, I do not.
8 Q. Could you please give the reasons for your view?
9 A.
The WSCC region is not a useful geographiu market for bulk power 10 analysis in this proceeding.
The areas within the WSCC region have very 11 different supply and demand situations and very different alternatives.
12 Combininj them into a large overall "market" obscures, rather than clarifies, 13 competitive relations and market alternatives.
The internal supply of generation 14 by qualifying facilities (QFs) in California, for example, is not of any 15 significance to the supply / demand situation in the Rocky Mount 4;n area.
A 16 power supply deficit area, such as California, has distinctly different needs and 17 alternates from an area such as the Arizona-New Mexico area, which has an 18 abundance of internal generation resources.
In addition to separate demand and 19 supply considerations, the WSCC regions also have limited transmission tio 20 each other.
All of the e factors strongly support regional rather than 21 aggregate markets.
22 As I have stated in my direct testimony (Exhibit No.14, at pages 7 23 to 13), a market is established in terms of its product, in this case bulk power, 24 and its geographic dimensions or boundaries.
In terms of physical boundaries, 25 the WSCC region consists of four distinct areas which result from the 26 concentration of loads and resources, such as water and coal.
These regions n e 1 a-
Exhibit No. 213 Page 30 1
are also characterized by internal transmission ties developed more extensively 2
than are inter-area linkages.
The WSCC has identified these geographic areas 3
for load and resource planning purposes:
the Northwest Power Pool Area, the 4
Rocky hiountain Power Area, the Arizona-New hiexico Power Area and the 5
California-Southern Nevada Power Area.
These four areas constitute the 6
relevant geographic markets for bulk power.
7 Dr. Taylor, incidentally, does not present any measures of the 8
competitiveness of the' WSCC-wide bulk power market he defines.
The measures 9
he does present are not for this market definition, but for specific transmission 10 links.
If he measured concentration in the bulk power market he defines, the 11 result would be to show very little, concentration.
12 Q.
Can you elaborate on your view that the WSCC regions differ signifi-13 cantly in resources?
14 A.
Yes.
As shown in Exhibit 214, Schedule 5, these regions have very 15 different mixes of generation.
While 66.1 percent of generation in the 16 Northwest Power Pool Area is conventional hydro, that percentage is 23.7 17 percent in the Rocky hiountain Power Area, 3.7 percent in the Arizona-New 18 hiexico Power Area and 20.2 percent in the California-Southern Nevada area.
19 The percentages of coal capacity are 23.4 percent, 63.6 percent, 50.9 percent 20 and 6.3 percent, respectively.
Likewise, the percentage of oil and gas capacity 21 ranges among the regions from 6 percent in the Northwest Power Pool Area to 22 over 61 percent in the California-Southern Nevada Power Area.
Furthermore, 23 while the California area can serve only about half of its peak load from the 24 least expensive resources ' hydro, nuclear. and coal) load could be served from 25 these sources in other areas the ratio is well over 100 percent in both summer 26 and winter, n e T R*
Exhibit No. 213 Page 31 1
Q. Dr. Taylor asserts, on page 23, that UP&L is aware that the entire 2
WSCC area is one market because that Company competes for bulk power sales 3
over the entire WSCC. Does that statement cause you to revise your opinion?
4 A.
No, it does not.
As I have stated many times, the question one 5
should be looking at in determining the extent of the relevant market is the 6
choices faced by buyers.
Electric utilities in the California area face a very
~
7 different situation from that of utilities in the Northwest.
Seasonal transfers 8
among the power areas notwithstanding, the very fact that Dr. Taylor argues 9
that inter-area transmission is an essential facility undermines the idea of a 10 WSCC-wide market for bulk power.
Opportunities are different in the different 11 power areas and prices are different as well.
The areas are the markets.
The 12 WSCC is not.
13 Q. Does UP&I s sale of power to Southern California Edison Company 14 (SCE) at Four Corners indicate that California and Utah are in the same market 15 along with Arizona and New Mexico, as Dr. Taylor states on page 247 16 A.
No, it does not.
SCE can purchase power at Four Corners in the 17 Arizona-New Mexico Power Area because SCE has built transmission lines to the 18 area, at great expense to itself, to bring energy to its retail and wholesale 19 customers in California from it-remote generating units at Four Corners.
l 20 UP&L has no rights to use those lines and does not do so. SCE does, either by l
21 buying power or by taking power from its own generation.
l l
22 Q. Dr. Landon, do you agree with Dr. Porter's (at pages 7 and 8) and l
23 Mr. Miller's (at page 11) assertion that, for the purpose of this merger, both l
l 24 the California-Southern Nevada and Arizona-New Mexico bulk power market 25 areas should be considered as one aggregate Southern market?
26 A.
No, I do not.
The differences in resources and loads, as well as the neTW
S.
~
Exhibit No. 213 Page 32 1
more comprehensive transmission interconnections within these areas than 2
between
- them, strongly support looking separately at their respective 3
alternatives (see my direct testimony, Schedule No.14, page 12, lines 23-25), an 4
example of the transmission limitations between regions has been identified _ by 5
Mr. Tucker in Exhibit No.12, at pages 32-33.
He testifies that the WSCC has 6
formed a committee whose sole purpose is to evaluate the simultaneous 7
transmission constraints from the Northwest and Arizona into the California 8
area.
These constraints are imposed on the operation of both the AC Pacific 9
Intertie and the AC transmission lines between Arizona and California.
These 10 constraints reduce flows between the California and Arizona markets.
In 11
- summary, geographical differences, the diversity of loads and resources, 12 transmission operating constraints between regions and historical patterns of 13 power and energy trading among major suppliers all confirm the appropriateness 14 of distinct regional markets.
It would be inappropriate to consider California-15 Southern Nevada and Arizona-New Mexico as one aggregate market.
16 Q. Dr. Landon, besides the factors mentioned above, have you assessed 17 the economic characteristics of the California-Southern Nevada and Arizona-New 18 Mexico markets and do you still conclude that both markets are distinctly 19 different?
20 A.
I have assessed the economic characteristics of the two markets in 21 terms of: (1) the number and relative size of buyers and sellers; (2) the volume 22 and frequency of transactions that occur in the market; (3) the cost and avail-23 ability of alternatives; and (4) the ease with which new participants may enter 24 the market (see my direct testimony, Exhibit No.14, page 7, lines 9-13.)
Based 25 on these generally accepted economic criteria, I conclude that California-26 Southern Nevada Power Area and Arizona-New Mexico Power Area are two n e ra-
Exhibit No. 213 Page 33 -
1 separate markets. My conclusion is based on the following items:
2 1.
There are more sellers in the California market, and the buyers 3
purchase in much greater volume.
The California market is, unlike the Arizona 4
market, an "import market" for both energy and power.
The Arizona-New 5
Mexico Power Area is a net exporter of energy.
6 2.
California imports substantially from the Northwest Power Pool 7
Area and the Arizona-New Mexico Power Area.
As shown, in Exhibit No.15, 8
Schedule 6,
in 1986 the California-Southern Nevada Power Area imported 9
20,151,369 megawatt-hours of energy from the Northwest and 8,112,116 10 megawatt-hours from the Arizona-New Mexico area.
In contrast, during that 11 same year, the Arizona-New Mesico area relied principally on its own 12 generation and imported only 744,803 megawatt-hours of energy from the 13 Northwest.
14 3.
In terms of the case with which new participants may enter the 15 market, I have stated in my direct testimony that barriers to entry fcr both 16 generation and transmission are relatively low (Exhibit No.
14, page 32).
17 However, unique to the California market, are the nontraditional sources of 18 power generation, such as are shown in my Exhibit No.15, Schedule 9. They 19 include QFs and other generators in California which produced 1,396 megawatts 20 of capacity in January 1987, while no generation of that type was found in the 21 Arizona-New Mexico area.
The existence of such nontraditional sources of 22 generation exemplifies the differences in environmental and administrative rules 23 that are prevalent in each market.
24 Q.
Dr. Landon, you have testified that the California-Southern Nevada 25 Power Area and the Arizona-New Mexico Power Area are not in the same 26 geographic market.
You have also testified that transmission service is not a l
Ile TR' L
)
Exhibit No. 213 7
Page 34 I
separate product market.
Ple:se accept as a hypothetical that this Commission 2
rules that the two geographic areas form one market and that a relevant 3
product market is transmission service.
How could we analyze the competitive 4
effect of the proposed merger on such a hypothetical market?
5 A.
Assuming the markets to be relevant, one woulf analyze this 6
hypothetical market like any other.
One would look at the al.ernatives facing 7
the participants in the market.
In this case, one would evaluate the capacities 8
of the transmission paths to and from the defined geographic area.
One would 9
look at the concentration of ownership or control of those paths.
One would 10 calculate the separate market shares of the merging entities, their combined 11 market share, and the HHI of the market so defined.
12 The rebuttal testimony of Mr. Tucker, Exhibit 211, discusses the 13 Southern Island of the WSCC, an area that corresponds to the geographic 14 market in this hypothetical example.
His Exhibit 212, Schedule 3, page 2 of 3, 15 show: the percentage of transmission capacity from the North into the Southern 16 Island area.
The table shows that UP&L holds a 7.7 percent share of the capacity whiite PP&L holds a 4.0 percent share.
The combined share of the 17 18 merged firm would be 11.7 percent.
Clearly, as Mr. Tucker's table indicates, 19 the shares of the two mersing firms, even after being combined through the 20 merger, are dwarfed by the shares of BPA (47.0 percent) and Intermountain 21 Power Area (25.2 percent).
The rank of the merged firm would be third among 4
22 six market participants.
The pre-merger HHI would be 3,029, while after the 23 merger it would rise to 3,091, an increase of only 62 points.
Note that this is 24 not a complete
- analysis, even of the transmission alternatives, of the 25 hypothetical Southern Island market:
It does not include the transmission ties 26 into the area from the East.
It should be viewed as a conservative (overstated) n e TR*
i.
Exhibit No. 213 Page 35
~
I statement of the market power of the six transmission participants.
An analysis 2
including all transmission alternatives to the Southern Island area would show 3
lower market shares for the merging firms and a lower HHI.
An analysis 4
including internal alternatives would show an even lower, and much more 5
correct, market share and HHI, 6
Q. Dr. Hughes has stated, at page 23 of his testimony, that prices of 7
bulk electricity are likely to be higher and the variety of supply "packages" 8
available to buyers will be reduced as a result of the merger. Do you agree?
9 A.
No. The price of bulk power supplies in any of the buying areas will l
l 10 be limited by the availability of alternative supply sources available to buyers.
11 In the California-Southern Nevada Power Area, Northwest utilities, including 12 PP&L and/or UP&L, must compete not only with each other, but with the 13 California utilities' own generation, QFs and increasing supplies from Arizona-14 New Mexico utilities.
Exhibit 214, Schedule 6 shows the sources of electricity 15 generated or received by utilities in the California-Southern Nevada area.
It 16 shows quite clearly that there were over 70 suppliers in 1986, counting all 17 cogenerators as a single entity.
It is unlikely that the merger of PP&L and 18 UP&L, ranked Nos.10 and 24, respectively, will have any effect on the variety 19 of supply packages available in the area.
20 In the Arizona-New Mexico area, a Northwest supplier must compete 21 with the area's own relatively low-cost nuclear and coal facilities, Rocky 22 Mountain suppliers and, possibly, even California suppliers.
As Dr. Hughes 23 points out at page 35, electric utilities in the Arizona-New Mexico area have a 24 significant volume of generating capacity in excess of current needs.
As can be 25 seen in Schedule 7 of Exhibit 214, the capability of conventional hydro, nuclear 26 and coal-fired generating plants are more than adequate to handle current peak I'1 O U n*
Exhibit No. 213 Page 36 1
loads in the Arizona-New Mexico Power Area.
In 1987, excess volume during 2
the summer was projected to be almost 11 percent and almost 50 percent during 3
the winter.
In fact, there is capacity in excess of current needs in three of 4
the four power areas.
Only in the California-Southern Nevada Power Area must 5
utilities rely on high-cost sources or imports to meet peak load.
This surplus is 6
expected to persist for several years.
Northwest power transferred over UP&L's 7
line into this area represents only one supply source for these buyers.
The 8
decrease in prices in 1986 as oil and gas prices fell, which is cited by Dr.
9 Hughes at page 65, indicates that the available alternatives are very good 10 substitutes.
Those alternatives impose a competitive ceiling on the price that 11 will be paid even if the merged entity controls 600 megawatts of transmission 12 capacity into the area.
This capacity, which represents only about 12.6 percent 13 of the total interregional transfer capacity into the Arizona-New Mexico area, 14 would not be sufficient to significantly affect the price in a market which 15 already has excess capacity and a total of 4,764 megawatts of transfer capacity 16 from other regions.
17 With a significant number of alternatives available in both buying 18 areas, particularly where the alternatives include surpluses of relatively low-cost 19 coal and nuclear-fueled facilities or cogeneration unrestrained by external 20 transmission requirements or costs, a single supplier could not command an 21 supra-competitive price.
Given that there are, in fact, significant alternatives 22 for supplies in California and the Southwest and the total volume of transfer 23 capability into these areas would not change, it is highly unlikely that the 24 prices of bulk power supplies will be higher as a result of the merger.
25 II. CONTRACTUAL AGREEMENTS VERSUS MERGER 26 Q.
Dr. Landon, in the direct testimony of Mr. Boucher, Exhibit 8, pages n e rn'
Exhibit No. 213
^
Page 37
~
1 36 to 38, he indicates that there will be many benefits as a result of the 2
merger between PP&L and UP&L, particularly with respect to the enhanced 3
ability of the combined comp;ny to engage in bulk power sales to utilities.
Are 4-you familiar with that testimony?
5 A.
Yes, I am.
6 Q. Several witnesses, among them: Lon L. Peters [ Exhibit No. 36, pages 7
22 to 24), Mr. Porter [ Exhibit No. 99, pages 21 to 23), Matthew I. Kahal 8
[ Exhibit No.18, pages 14 to 16), Whitfield A. Russell [ Exhibit No. 20, pages 42 9
to 43] and Dr. Taylor (Exhibit No.178, page 13), state that the merger is not 10 necessary for those sales to occur.
They assert that it is generally accepted in 11 economics that if transactions are economically justified, those transactions will 12 occur regardless of who owns the resources involved.
Ownership, in their 13 views, is irrelevant to the question of which economic activities will occur in i
14 the market.
If this were true, the companies ought to be able to contract with 15 each other and derive the same benefits. Do you share this view?
l 16 A.
No, I do not. There is a well developed body of economic theory on 17 contract governance which indicates that because of transactional costs, it is 18 often more beneficial for companies to operate as a single entity than to rely l
19 on ' bilateral or multilateral contracts.
Transaction costs include the following:
20 (1) costs of negotiating contractual agreements among various parties that have j
21 different perceptions of the levels of risk and uncertainty; (2) costs of writing 22 a comprehensive contract that covers all current and future contingencies; (3) 23 costs of monitoring contractual performance; and (4) costs of enforcing 24 contractual promises.
Transactions involving regulated utilities abo include 25 costs derived from regulatory review and oversight.
In each case, there are the l
l 2o recurring costs of acquiring and processing information in addition to legal l
l n e rn-I
q Exhibit No. 213 Page 38 1
costs and costs associated with the decrease in economic flexibilities. in pricing 2
and production imposed by the contract itself.
Indeed, by their very nature, 3
contracts impose restrictions not only on the current, but also on the future, 4
behavior of economic actors who will not be able to react quickly to market 5
changes.
It makes economic sense to internalize activities within a single 6
entity when avoided transactional costs are high.
7 Q. Dr. Landon, with regard to the electric utility industry, what factors 8
contribute to the high costs of market transactions relative to the efficiency of 9
a merger?
10 A.
Market transactions in the electric power industry tend to be 11 characterized by uncertainty and complexity, asset specificity, sunk costs and 12 infrequency of orders.
These facts lead to the conclusion that when market 13 transactions must replace internal organization, those transactions are likely to 14 be governed by complex long-term contracts with their attendant costs and 15 inflexibilities.
Schedules 8 and 9 are articles from the professional economic 16 literature which describe these costs and their consequences.
These elaborate 17 on the costs of contracting between separate parties.
18 Q. Can you provide an example of a transaction which is much less 19 costly when entered into by an integrated firm?
20 A.
Yes.
Where an investment (such as a transmission line) has a 21 positive net value (excess of benefits over costs) only if its use can be 22 constantly adjusted to reflect market changes, the investment may be impossible 23 to arrange through contracts between parties with substantially different 24 interests.
Uses of the line which maximize the benefits to the separate parties 25 may not maximize mutual benefits. It may not be possible to anticipate all uses 26 that may arise or to establish a contract governance which will continually li e I'n'
Exhibit bio. 213 Page 39 1
make the optimal decisions.
This investment would be made by an integrated 2
firm, not by separate entities.
3 III. ALLEGED VERTICAL EFFECTS OF THE MERGER 4
Q. Dr. Landon, at page 35 of your direct testimony, Exhibit No.14, you 5
asserted that the combined utility would not be able to charge more for North-6 west energy than UP&L !s able to charge now.
What economic basis is there 7
for this conclusion 7 8
A.
There are two factual and theoretical bases.
First, the large number 9
of utilities that can supply power at Four Corners and the relatively low-cost 10 alternatives of the buyers would lead me to expect that UP&L is usually a 11 price-taker at Four Corners and exercises little influence over the general price 12 level there.
That is, UP&L's contribution to the total volume of bulk power
^
13 available at Four Corners, whether generated or imported, is not large enough 14 to be able to affect the price there.
Because utilities in that area have many 15 alternatives to turn to for power, UP&L has very little influence.
I have 16 confirmed this factual situation by interviews with UP&L personnel.
17 But even if, contrary to the evidence, UP&L has monopoly power by 18 virtue of its ownership of inland transmission capacity between the Northwest 19 and the Southwest.
Economic theory indicates that it is quite unlikely that the 20 merger would have any adverse consequences on competition in any of the 21 relevant markets.
Indeed, even assuming that UP&L has such market power, 22 the most likely outcomes of the merger are:
(1) increased price competition in 23 the Northwest bulk power market, which leads to; (2) lower resale prices 24 charged by UP&L to the Southwest buying market; and (3) increased 25 transactions between the Northwest and Southwest when transmission capacity 26 through UP&L is available.
The rationale for these outcomes can be illustrated 11 0 l'n'
o Exhibit No. 213 Page 40 1
in a series of hypotheticals.
2 Q. What do the hypotheticals do?
3 A.
I have developed three simple examples that illustrate the likely 4
results of a merger under different market conditions in both the Arizona-New j
5 Mexico Power Area (the Southwest) and in the Northwest Power Pool Area (the 6
Northwest).
These examples are hypothetical in that they use simplifying l
7 assumptions in order to clarify the process.
The examples effectively examine 8
the merger as a "vertical issue," as Dr. Hughes, on page 102, suggests is the 9
proper way w look at it.
10 First Hvoothetleal 11 Q. What are the assumptions that underlie your first example?
12 A.
The assumptions are:
13 1.
That UP&L controls only a transmission line connecting the 14 Northwest with the Southwest (i.e.,
it does not generate itself 15 and has no other customers.)
16 2.
That UP&L has no influence over the price of energy in the 17 Northwest (i.e., that the wholesale market in the Northwest is 18 perfectly competitive.)
19 3.
That control over the.line does give UP&L some influence over 20 the price of energy in the Southwest (i.e., UP&L is not a price-21 taker and greater sales can be made only by reducing price.)
L 22 It-this example, the difference between what UP&L pays for power j
23 and the price it receives for the power in the Southwest is implicitly the 24 transmission fee it receives.
As an independent entity, the price for which 25 UP&L can resell Northwest energy depends completely on the nature of demand l
26 in the Southwest.
Its profit depends on the price that it pays for power in the 11 O l'n'
Exhibit No. 213 Page 41 1
Northwest and its transmission cons.
The way a seller exercises market power 2
is to restrict output, that is,
'.o produce less than it would if its actions had no 3
effect on price.
UP&L would set a profit-maximizing (output-restricting) price.
4 It would lower its offer price to increase sales only as long as the revenues 5
from added sales grew faster than the added cost of purchases and transmission 6
(so long as marginal cost is less than marginal revenue.)
The additional costs 7
will equal the price it pays for power in the Northwest plus its transmission 8
costs.
The added revenue from increased sales will depend on the elasticity of 9
demand in ti e Southwest.
10 Now let us examine what happens in this example when PP&L and 11 UP&L merge.
The merger has no effect on the residual demand curve of 12 Southwestern buyers for purchases from the Northwest through UP&L's system.
13 It has no direct effects (in this simplified example) on UP&L's transmission 14 costs.
The merged entity will continue to maximize profits by choosing a price 15 and quantity for sale from the Northwest such that revenues from additional 16 sales exceed its marginal cost (the cost of the power in the Northwest plus 17 transmission costs.)
Because the wholesale market in the Northwest is perfectly 18 competitive, the marginal cost of PP&L's generation is simply equal to the 19 competitive market price.
PP&L will supply no more and no less than it would 20 absent the merger.
Similarly, third-party sales will also be unaffected.
In this 21 case, the merger can have no effect on prices upstream or downstream.
UP&L 22 has exactly as much market power before the merger as after the merger.
23 Nothing changes as a consequence of tne merger in this hypothetical example.
24 (Obviously, these examples ignore other economies that may result from the 25 merger and assume that UP&L is not a price taker in the Southwest.)
26 11 O rn'
e 4
Exhibit No. 213 Page 42 1
Second Hvoothetical 2
Q. Dr. Landon, what would happen if the Northwestern market were 3
imperfectly competitive and the price of electricity in the Northwest is above 4
marginal cost?
5 A.
As you suggest, a price above marginal cost means that the sellers' 6
market in the Northwest is imperfectly competitive.
That is, the price for 7
wholesale power 11 greater than marginal cost.
I will continue to assume that 8
UP&L cannot affect that price.
The source of the imperfect competition is not 9
really important.
10 Before the merger, UP&L must buy Northwestern power at a price 11 that is greater than the marginal cost of the suppliers, that is, a price higher 12 than in the first hypothetical described above.
In this second example, the 13 demand of Southwestern buyers does not change nor do UP&L's transmission 14 costs.
UP&L maximizes its profits in much the same way as before.
Because 15 the price it pays for power in the Northwest is higher here than in the first 16 case, the price it charges in the Southwest will also be higher and the quantity 17 sold will be lower.
The level of additional revenue required to make an 18 additional sale profitable has been raised.
19 Now, if PP&L and UP&L merge, the combined utility will have the 20 choice of using PP&L's generators or buying from other Northwest suppliers.
21 Other factors are the same.
The merged entity will maximize profits by 22 choosing a price and quantity for sales to the Southwest that equate marginal 23 revenue with the sum of UP&L's transmission costs plus PP&L's marginal 24 generating cost if it is less than the price of alternative Northwest power.
25 That is, the only thing that changes is that the merged entity will make 26 decisions based on the marginal cost to PP&L of generating (or purchasing) n O I'n'
r N
e.
Exhibit No. 213 Page 43 1
power rather than on the supra-competitive prices charged by other North-2 western suppliers in the market.
(We are already assuming that PP&L's 3
marginal generating cost is less than the price of power in the North, vest 4
because that market is imperfectly competitive.)
As a result, it will benefit 5
UP&L to reduce the price it charges to Southwestern utilities from the level 6
before the merger in order to increase the amount scid.
The merger eliminates, 7
or at least reduces, the adverse economic distortion that results from the 8
compounding of imperfect competitioit at different stages of a vertical chain of 9
production (i.e.,
the well-known problem of double-marginalization.)
UP&L, 10 which by assumption here has monopoly power in sales to the Southwest, would, 11 absent the merger, mark up a price that has already been marked up as a 12 consequence of imperfect competition in the Northwest.
The merger limits the
~13 markup on transmission te a markup over marginal cost.
Buyers in the 14 Southwest get lower prices and increased supplies.
15 It is important to recognize that in this case the merged entity will 16 find it profitable to increase wholesale transactions.
The additional production 17 will come from PP&L's generators unless the merged entity's ability to produce 18 power at a cost less than the Northwest market price leads to more price 19 competition and lower prices in the Northwest.
The merged entity will always 20 maximize profits by choosing to buy from a third party if the price the third 21 party charges is less than PP&L's internal marginal cost of generation.
22 Whether or not the merger leads to more price competition in the 23 Northwest, both the merged entity and its customers in the Southwest benefit 24 from the merger.
Other suppliers in the Northwest will lose profits either 25 through lost sales or more price competition.
However, these lost profits are 26 entirely a reduction of the economic rents (discussed in Section V) that they n U U n'
.[.
Exhibit No. 213 Page 44 I
were earning prior to the merger in this example.
The competitors in the 2
Northwest may not like having their market power diminished, but the antitrust 3
laws are not designed to protect competitors from transactions that directly or 4
indirectly increase price competition.
If the competitors complain vigorously 5
about a merger, it may be because the merger will increase competition.
6 Third Hvoothetical 7
Q. Dr. Landon, how does the situation change if UP&L not only buys 8
and sells energy, but also generates energy itself?
9 A.
Now we are changing our first assumption.
Rather than simply 10 owning a transmission line, let us assume that UP&L also owns generating 11 capacity which it uses to serve retail customers in Utah as well as, possibly, 12 wholesale customers in the Southwest.
UP&L can now purchase power from 13 Northwestern utilities and integrate its purchases with its own resources.
14 Absent the merger, UP&L would purchase power for its own use up 15 to the point where the price it pays equals the additional cost of internal 16 generation in order to minimize its total generation costs.
It will then 17 determine how much energy to sell in the Southwest and at what price it would 18 make such energy available, in much the same manner as in the previous 19 examples.
The decision would be based on the demand curve of Southwestern 20 buyers and its own marginal generation and transmission costs.
21 The effects of a merger would depend on whether UP&L's purchases 22 in the Northwest are made at a price equal to marginal cost in that area.
If 23 the Northwest price is equal to the seller's marginal cost, then there will be no 24 effect on prices or quantities compared to the situation before the merger.
25 This is because UP&L could already buy power in the Northwest before the 26 merger at marginal cost. It can do no better than this by merging.
11 e l'n'
4 Exhibit No. 213 Page 45 1
However, if competition is imperfect so that the Northwest price is 2
above marginal cost in that area, then we are back to the situation in the 3
second hypothetical discussed earlier.
The dispatch of UP&L's generating units 4
will now be based on PP&L's marginal production costs, which are by assump-5 tion, lower than market prices.
Alternatively, the threat of more PP&L/UP&L 6
transactions could lead to more price competition in the Northwest.
Then 7
cheaper power purchased from third parties in the Northwest could be 8
substituted for production from UP&L's plants.
The merged entity's costs of 9
generation will fall since cheaper PP&L power or cheaper power from 10 competitors will be substituted for generation from UP&L's plants.
Retail rates 11 for the merged entity will fall as well.
The merged entity's marginal generation 12 costs for wholesale transactions to the Southwest are also likely to fall so that 13 prices charged for sales to Southwestern utilities are likely to fall.
As in the 14 second ca'e discussed above, the benefits from the merger arise from the s
15 reduction in the burden associated with double markups.
16 The only potential adverse effect on competition in this hypothetical 17 could arise from increased concentration in the Northwestern generation supply 18 market rather than from UP&L's transmission capacity constraints.
This is 19 clearly not in line with the facts of this merger.
As my direct testimony 20 indicates, the increase in concentration in the Northwest resulting from the 21 merger is small and there are other reasons to believe that competition in the 22 Northwest will not be reduced.
23 Q. Dr. Landon, what do you conclude from these examples?
24 A.
I conclude that even if we assume that UP&L had market power as a 25 seller in the Southwest, the merger would lead to either lower prices there or 26 no change in prices.
In almost all conceivable cases, the merger either 11 O l'n'
,'I Exhibit No. 213 Page 46 1
increases efficiency or leaves it unchanged.
2 Q. Which of these cases do you think is the most consistent with the 3
facts?
4 A.
I do not think that any of these cases is likely to be consistent with 5
the facts.
I have gone through them to show that even if we assume that 6
UP&L has market power in the Southwest, a "vertical' merger with PP&L 7
carnot lead to higher prices or costs.
As my testimony indicates, I do not 8
believe that UP&L has market power either in the Northwest er in the 9
Southwest.
The reasons for this conclusion are stated elsewhere in this and in 10 my direct testimony.
It is conceivable, however, that IPC exemises some 11 market power and charges wholesale prices that are above competittve levels.
12 If this is the case, the merger unambiguously increases efficiency, loww prices 13 charged to the Southwest and increases the volume of trarasetions 50i4 t there 14 when transmission capacity is available.
15 Q. Dr. Hughes argues that your analysis on these points is correct for 16 unregulated markets (page 57), but is not correct for regulated markets. Do you 17 agree with him?
18 A.
I agree that my analysis is correct for unregulated markets.
I also 19 believe that his arguments about the effects of regulation on these results are 20 incorrect.
In particular, I do not believe that the merged entity, as a 21 consequence of regulation, will give a
preference to high-cost internal 22 production when lower priced power is available from third parties in the 23 Northwest.
24 IV. PREFERENCE FOR INTERNAL GENERATION AND REGULATORY EVASION 25 Q. Dr. Hughes asserts, at page 50 to 56, that if PP&L and UP&L merge, 26 the new entity would exercise a preference for bulk electricity transactions 11 e r a-
.b Exhibit No 213 Page 47 1
using PP&L generation at the expense of less costly energy from other 2
Northwest suppliers. Would you please comment on this point?
3 A.
Yes, I will.
First, let me state that the theory I referred to in my 4
direct testimony on this matter (Exhibit 14, pages 34 to 35) does refer to the 5
case of a firm attempting to maximize its profits, as Dr. Hughes suggests on 6
page 57 of his testimony.
The examples that I have just presented are simply 7
an elaboration of that theory.
However, despite Dr. Hughes' suggestion to the 8
contrary, the theory applies just as well to PP&L and UP&L in the present 9
situation and will apply to the merged entity in the future. There is no reason 10 to accept Dr. Hughes' assertion that regulated firms, such as the merged utility 11 or the existing utilities, do not also have a strong incentive to mir.imize their 12 costs whether for their own account or for resale.
UP&L has for years 13 purchased power from the other utilities in the Northwest when it could save 14 money by doing so.
Mr. Veri R. Topham's Schedule 200 of Exhibit 199 shows 15 the amounts of Northwest power UP&L purchased in each year from 1983 16 through 1987.
It shows that most of that power was purchased for the express 17 intent of serving its own load.
UP&L clearly has made frequent purchases of 18 Northwest energy when it was available at lower cost than its o w n internal 19 generation.
20 Regulated utilities, such as PP&L and UP&L, the merged utility and 21 even IPC and MPC, have significant incentives to minimize costs by buying less 22 expensive power from outside their systems if it is available.
First, regulated 23 utilities must face the probability that the commissions that regulate their 24 prices will monitor their performance.
Utilities have a burden of showing that 25 they are managing effectively and prudently.
Part of that burden is to 26 demonstrate that costs are minimized.
It is inconceivable that a utility would 11 O l'R'
ll'
[.
Exhibli No. 213 Page 48 1
willingly put itself in the position of having to admit to a regulatory body, 2
which sets its retail rates, and has the ability to withhold compensation for 3
costs deemed imprudent, that it deliberately used more expensive resources than 4
are necessary to provide service.
Second, the utility must meet competition.
5 Whether it is competition for nonfirm sales to other utilities or competition to 6
retain dual-fueled industrial customers, the utility has a strong incentive to 7
keep rates low by using the lowest cost resources.
Third, since costs and 8
revenues from nonfirm transactions are passed on to ratepayers, there is no 9
benefit to the utility to using internal resources when external sources are less 10 expensive.
For these reasons, I conclude that the merged utility will not have 11 any incentive to refuse to purchase energy from other Northwest utilities, 12 including IPC and MPC, when such power is available at a price below its 13 internal cost of generating the same power from its own plants.
14 Q. Dr. Hughes expresses concerns at page 54, that, if the merger is 15 approved, bulk power transactions currently under FERC regulation will become 16 internalized and escape regulatory oversight. 'is this a valid concern?
17 A.
No.
Dr. Hughes argues that by vertically integrating, PP&L and 18 UP&L will avoid FERC regulation of "internal" transmission fees and will be 19 able to bundle internal power production with monopoly transmission fees.
Dr.
20 Hughes offers no support for this conclusion which is incorrect and not a 21 logical outcome of the merger.
22 Q. Why is Dr. Hughes' conclusion incorrect?
23 A.
In the first place, UP&L has been purchasing and reselling for years 24 on more or less the same basis.
I know of no reason to assume, as Dr. Hughes 25 does at page 56, that any drastic change would soon have been implemented.
If 26 anything, the FERC's recent decision in the Baltimore Gas and Electric Company 11 e I'n'
l Exhibit No. 213 Page 49 I
proceeding went a long way towr,rd sanctioning the use of price as an 2
appropriate method of allocating scarce transmission capacity.
In addition, 3
FERC regulates both transmission and purchased power contracts.
All bulk 4
power sales, whether they be sales by PP&L wheeled through UP&L or combined 5
bulk power and transmission contracts, would still be subject to FERC 6
regulation.
I can see no reason why FERC regulation over purchr. sed power 7
should be assumed to be less effective than FERC regulation over transmission.
8 Dr. Hughes has not presented any evidence that would support such a 9
conclusion.
10 Q. Why is Dr. Hughes' conclusion not likely to be an outcome of the 11 merger?
12 A.
Dr. Hughes' conclusion assumes two things:
(1) that UP&L has 13 market power over bulk power sales to the Southwest, i.e., that it uses its 14 transmission system to make monopoly profits; and (2) that the merged company 15 will favor internal production which has higher marginal costs than its 16 competitors to evade FERC transmission rate regulation.
These assumptions and 17 the conclusions that flow from them are not consistent with the facts.
18 Monopoly profits are made by restricting output to raise prices above 19 a competitive level. Reducing use of the UP&L transmission line is the opposite 20 of what the merged companies propose.
The merged company plans to try to 21 increase the utilization of the transmission system, not restrict it.
This is 22 hardly what a firm with enhanced market power would do.
Dr. Hughes' 23 assumption of enhanced market power of the merged firm (pages 50 to 56) 24 contradicts the acknowledged intention for the merged firm to increase, rather 25 than restrict, use of the UP&L transmission system.
26 Dr.
Hughes' second assumption, at page 54, that the merged 11 0 l'n'
y, Exhiblt No. 213 Page 50 1
companies will favor internal production at higher marginal costs over purchases 2
from competitors to evade FERC regulation of UP&L's "monopoly" transmission 3
charges, is also inconsistent with the facts.
This assumption requires that:
(1) 4 UP&L has monopoly power as a seller in the Southwest; (2) FERC would have 5
forced UP&L to stop engaging in buy / sell transactions; (3) UP&L would have 6
agreed to wheel as an alternative; (4) FERC would have established wheeling 7
rates based on some simple cost of service formula; and (5) state and federal 8
regulators would have permitted the mern,ed company to use high cost internal 9
generation when lower priced power is available from third parties for resale in 10 the Southwest.
I do not believe that any of these assumptions, all of which are 11 necessary for Dr. Hughes' conclusions, are consistent with the facts.
12 The merged company is generally a price-taker when it sells to 13 utilities in the Southwest and/or California, and does not have monopoly power 14 as a seller in the Southwest.
It is a price-taker because there are maay good 15 substitutes for its power:
(1) purchases through California from the Northwest; 16 (2) intraregional purchases; (3) purchases from nonutility
- sources, i.e.,
17 cogenerators and small power producers; and (4) internal generation.
In 18 addition to being a price-taker, the merged company can be assumed to be a 19 profit maximizer.
The way for the merged company to maximize profits at any 20 given price is to purchase the lowest cost resources or supplies.
In this case, 21 it would be illogical for the merged companies to favor internal production if it 22 can purchase cheaper energy from third-party suppliers, including its 23 competitors.
24 I have seen no evidence that FERC has proposed to restrict UP&L's 25 ability to buy surplus power in the Northwest when it can economically replace 26 its own generation and simultaneously sell power in the Southwest.
Many n e ru-
'i Exhibit No. 213 Page 51 1
utilities engage in exactly the same practice.
2 If FERC could order UP&L to wheel, or if UP&L chose to do so 3
voluntarily, it is unlikely that wheeling rates would be limited to simple 4
accounting cost values.
As I discuss in more detail below, when economic 5
conditions in California and the Southwest have led to a significant demand for 6
Northwestern power, UP&L's transmission lines would often be fully loaded.
A 7
market-clearing price required to ration scarce transmission capacity would be 8
indicated and UP&L would be well advised to seek authority to auction off 9
scarce transmission capacity in excess of its own requirements as Baltimore Gas 10 and Electric Company has been permitted to do, 11 Finally, there is no realistic way for the merged company to separate 12 internal production for its own use from internal production dedicated for 13 resale.
As I have already indicated, state regulators will not look favorably on 14 the merged company's use of internal production when lower priced sources are 15 available from third parties.
If the merged company tried to evade FERC 16 regulation as Dr. Hughes has suggested at page 25, it would run a much more 17 serious risk of state regulators disallowing the costs of power produced in 18 excess of the prices at which energy could otherwise be obtained from third 19 parties in the Northwest.
20 Dr. Hughes' arguments at pages 60 to 62, regarding favoring costly 21 internal production.in an effort to evade FERC transmission rate regulation 22 require that all of the above assumptions be factually correct.
I believe that 23 none of them are factually correct.
Since the "regulatory evasion" theory forms 24 the entire basis for Dr. Hughes' arguments that there are
- vertical problems" 25 resulting from the merger, the failure of the regulatory evasion theory to be 26 consistent with the facts means that the only potential problem that Dr. Hughes l'a e l'n'
..n..
Exhibit No. 213 Page 52
+
I can suggest concerning the merger does not exist.
2 Q. Has UP&L bought from outside sources when those sources are priced 3
lower than its own marginal costs?
4 A.
Yes.
In every year UP&L has purchased significant quantities of 5
Northwest power as hir. Topham's Schedule 200 shows.
For example, in 1986, 6
UP&L backed down its own generation and related coal production to take 7
advantage of bulk power that was lower in cost than its marginal cost.
Such 8
behavior is inconsistent with Dr. Hughes' assumption, at page 62, of favoring 9
higher marginal cost internal production.
If IPC and hiPC price their product 10 at marginal cost, and that cost is lower than the marginal cost of internal 11 production, it would be logical for the merged companies to buy it, as UP&L 12 has done in the past.
It is of course conceivable that IPC and hiPC have been 13 able to charge prices above marginal cost because they are exercising market 14 power in the Northwest (i.e. the margins are not normal economic rents--see 15 below). If this is the case, the merged company will favor its own generation as 16 long as its marginal cost is lower than the monopoly prices charged by IPC and 17 biPC.
However, this would be a very pro-competitive outcome of the merger.
18 It would allow the merged company to lower its costs by avoiding the monopoly 19 prices of PP&L's competitors.
They would either have to lower their prices to 20 compete or lose the business.
The merged company's costs would fall, 21 competition in the Northwest would be stimulated, prices in the Southwest 22 would either remain the same or fall, the merged company's margins might 23 increase, and the amount it sells in the Southwest would increase.
IPC and 24 htPC would be losers, but only losers of monopoly rents.
25 Q. What additional evidence is there that generation sources in the 26 Northwest have market power and have set their prices to extract monopoly n e r a-
q
(
Exhibit No. 213 Page 53 1
rents?
2 A.
In response to UP&L and FP&L's Second Data Request to Idaho 3
Power Company and Montana Power Company No. 27, IPC admits that the price 4
of surplus sales is based on "the price that purchasers are willing to pay for 5
such energy" in addition to the cost of production from IPC's hydro operations.
6 I have included this response as Exhibit 214, Schedule 10.
7 In addition, evidence of market power by Northwest generation 8
sources can be found in the response supplied by Dr. Taylor to UP&L and 9
PP&L's Second Data Request to Colorado River Energy Distributors Association 10 (CREDA) No. 40.
Dr. Taylor's response to this data request includes !! non-11 consecutive pages of transcript of the testimony of R.V.
Knapp, Southern 12 California Edison Manager of Steam Generation, in Cities of Anaheim. Riverside.
13 Bannine. Q1 ton and Arusu. California v.
Southern California Edison Comoany, 14 United States District Court, No. 78-0810-WMB.
Page 5 of 11 of the response 15 submitted by Dr. Taylor (which is page 237 of the traascript) contains the 16 following testimony:
17 In fact, my understanding is that at the present time that we 18 are not routinely scheduling energy down the Pacific Intertie i
19 because the price set by Bonneville is not economic with other 20 resources, including our own resource.
21 21 However, we are from time to time buying from Utah Power 23 and Light energy that they have been sold by Bonneville that 24 is marked up by Utah Power and Light and in the process is 25 now economic to us whereas that same energy that was 26 available to us down the intertie is not.
27 28 Q. Are you saying then that Utah is able to buy from 29 Bonneville at a price different than what Bonneville was 30 offering Edison?
31 32 A.
That is correct because even though they don't physically 33 lie in the northwest they are part of the pooling arrangement 34 and enjoy benefits the same as being in the Pacific Northwest.
35 11 e i n-
4-E-
Exhibli No. 213 Page 54 1
Q. So in the instance you just described, what's happening is 2
that even with Utah's markup, it's less in price than if
+
3 Bonneville had sold it directly to yoe?
4 5
A.
That's my understanding, although I'm not directly involved 6
in that at the present time.
7 In the instance cited by Mr. Knapp, UP&L was using its transmission 8
to enhance competition and increase the supply of economic bulk power in the 9
California-Southern Nevada market by providing a viable alternative to BPA 10 which was pricing its hydro power above competitive market levels.
UP&L was 11 promoting price competition among Northwest generators and at the same time 12 increasing the supply of bulk power to the California-Southern Nevada market.
13 UP&L's activities were clearly competition-enhancing and not the exercise of 14 market power.
The quotation also strongly reinforces the need to consider all 15 market alternatives.
16 Q. Dr. Landon, have you read Dr. Porter's testimony on the subject of t
17
' regulatory evasion?
18 A.
Yes, I have.
Dr. Porter argues, at page 18, that one example of how 19 an owner of transmission capacity could avoid regulation of his transmission 20 services price is to pay too little for buik power.
This is not a regulatory 21 evasion argument, but one about market power in buying.
It also hypothesizes 22 behavior exactly the opposite of that suggested by other witnesses.
Dr. Hughes j
23 suggests at pages 50 to 56, that the merged firrr will generate power from its 24 own plants even if the alternative would be less costly power in the Northwest.
25 Under Dr. Porter's scenario, at pages 16 to 18, prices in the Northwest can be 26 driven down only if they are currently greater than marginal cost.
Driving 27 dowre prices would enhance competition, not reduce it.
Under this assumption, 28 the merger would enhance competition in the Northwest and lower prices l
11 O l'R*
i
g J.
Exhibit No. 213 Page 55 1
elsewhere, hfy testimony discusses this issue in Section IV, 2
Q. Dr. Landon, have IPC and hiPC considered alternatives to use of the 3
PP&L and UP&L transmission systems?
4 A.
Yes.
Information on alternatives that they have considered is 5
contained in confidential Schedule 11 to Exhibit 214.
6 V.
RENTS ON GENERATION 7
Q, Dr. Landon, Dr. Hughes refers to the "cos t" of energy from the 8
Northwest at pages 60 to 61, but you spoh i its "price."
Is there a 9
difference between these terms as they relate r the incentive of the merged 10 utility to purchase Northwest power?
11 A.
Yes, there is.
Dr. Hughes refers to the marginal cost to IPC and 12 htPC of producing additional power to sell to other utilities (page 62).
This is 13 what is meant by "co s t."
Th'e "price" is what another utility pays for the 14 power.
The Northwest utilities would choose to make additional sales or.ly if 15 they are able to do so at or above a price that compensates them for their 16 marginal costs.
hfarginal cost, in other worris, is a minimum for short-term 17 transactions.
18 Q. Does Dr. Hughes indicate that price and marginal cost are the same 19 number where sales in the Northwest are concerned?
20 A.
Not exactly.
Dr. Hughes, at pages 61 n 62, indicates only that from 21 society's point of view, the energy with the lowest marginal costs should be 22 sold first.
There is nothing to indicate that price and marginal cost will always 23 be equal.
A rational seller will not sell if the price falls below cost.
Sales 24 will continue to be made as long as the price exceeds marginal cost.
To the 25 extent that price does exceed marginal cost there is additional profit to be 26 made. This is known as an economic rent.
11 O l'R'
c.
. [4 ',,
Exhibit No. 213 Page $6 1
Q. Do IPC and MPC earn economic rents on their bulk power sales to 2
other utilities?
3 A.
Apparently, yes.
If Dr. Hughes is correct about the marginal cost of 4
energy from those companies' generators,.both IPC and MPC are able to extract 5
an economic rent from their sales.
Exhibit 214 Schedule 12 shows that both 6
IPC and MPC made substantial sales to PP&L and UP&L during 1986 at prices in 7
excess of the marginal costs Dr. Hughes identifies, at pages 63 to 64, for those 8
companies.
This indicates that those companies are able to extract for 9
themselves at least some available economic rents by selling at prices above 10 marginal cost to their bulk power customers. PP&L and UP&L.
11 Q. Dr. Landon, is it reasonable that utilities such as IPC and MPC 12 should be able to make sales to other utilities at prices in excess of their 13 marginal costs?
14 A.
Of course it is reasonable, assuming that they buy in a competitive 15 market and sell in a competitive market.
The price of Northwest economy 16 energy rises and falls according to the hydro conditions and the seasons.
There 17 is very little that any single company can do to influence that price.
The 18 market sets it.
IPC and MPC are very fortunate that they are located in an 19 area where supplies of resources to be converted into electricity at relatively 20 low cost are abundantly available.
IPC has considerable hydro-electric 21 generating capability.
Both utilities have mine-mouth plants located next to 22 very low-cost strip mines.
The ratepayers and stockholders benefit from those l
23 natural resources.
4 24 Q. What is the proper vantage point from which to examine economic 25 rents?
26 A.
Economic rent can occur from two causes.
The first source is from n e ru-
li Exhibit No. 213 Page 57 1
the scarcity of ecc;;cM :isources.
The second is from market power.
Rents 2
from this latter source can be viewed as monopoly rents.
The difference is 3
crucial.
4 Rent from economic scarcity is a normal fact of life that we accept 5
without problem.
For example, Dr. Hughes points out that: "Surplus hydro has 6
near zero marginal cost.
Hydro surplus energy is generally priced to meet a 7
competitive price, which is approximately the marginal cost of the marginal 8
steam-electric unit in the market."
(page 61, lines 10 through 14.)
It is 9
generally accepted that all of the available hydro-electric energy that can be 10 produced is generated and sold to willing buyers.
Price is used merely as the 11 rationing device.
If IPC is able to extract an economic rent in selling surplus 12 hydro-electric energy to other utilities, there is no economic problem.
The 13 appropriate resources are still being used.
IPC charges a higher price and is 14 better off than it would have been if it sold at marginal cost.
Similarly, the 15 purchasers are worse off.
But there is no loss to society, or "deadweight loss" 16 in this situation; society's interests are not harmed.
There has been an i
17 allocation of benefits between the parties to the transaction.
This is referred 18 to as a "normal rent."
Dr. Porter discusses the concept of a deadweight loss in 19 his testimony at page 17.
20 Economic rents become monopoly rents when associated with the con-21 striction of output.
In this case, a seller would withhold a portion of his 22 supply in order to raise its price above marginal cost.
Suppose, for example 23 that IPC, rather than generating as much hydro-electric energy as possible.
24 were to let water spill over the dams in order to get a better price for the 25 remaining energy generated.
Successful exploitation of this technique would 26 result not only in an a!!mtion of the benefits to IPC, but there would also bc n e l'n'
[.
Exhlbli No. 213 Page 58 1
a deadweight loss, or loss to society due to IPC's exercise of monopoly power.
2 This type of rent is called a "monopoly rent."
3 Q. What kind of rent is achieved by IPC and MPC when they sell power 4
to other utilities at a markup?
5 A.
Because those utilities are selling in a competitive market, it is most 6
likely that they achieve only normal (nonmonopoly) rents.
It would not be 7
profitable for them to attempt to get higher prices by constricting output.
8 Q. What about the situation with UP&L's ownership of the line from 9
Pinto to Four Corners or its other transmission?
10 A.
Any rents that may be collected by UP&L through the use of these 11 lines are also normal rents.
The lines in question are used to capacity when 12 there is a price differential between the Northwest and the Southwest that 13 makes transactions economic.
The de facto "price" of the use of these lines 14 effectively rations the use of a scarce resource.
This rationing through the 15 market is more efficient than an administrative allocation scheme and it 16 provides incentives to expand the scarce resource.
17 Q.
Does Dr. Hughes provide any information relevant to determining 18 whether rents associated with scarce transmission capacity are normal or j
19 monopoly rents?
20 A.
Dr. Hughes provides two pieces of information that suggest that there 21 are in fact economic rents associated with scarce transmission capacity.
- First, 22 at pages 53 and 84, there is excess demand for the transmission line identity 23 (IPC and MPC want at least 300 megawatts and PP&L/UP&L want 650 f
24 megawatts).
Second, there has been a big wedge between marginal costs at 25 Four Corners and marginal cost in the Northwest, even when UP&L's lines have i
26 been fully loaded.
Remember, a monopolist restricts output.
If there are 11 O l'n'
Eshlblt No. 213 Page 59 1
economic rents when capacity is fully utilized, then they are "ordinary" rents, 2
not monopoly rents.
3 VI. RETAIL COMPETITION 4
Q. Dr. Landon, have you reviewed the testimonies of Dr. Gcrdon T. C.
5 Taylor and Mr. Matthew Kahal regarding the effects of the merger on retail 6
competition?
7 A.
Yes, Dr. Taylor takes excep' ion to my conclusions that there would 8
be very little, if any, change in fringe or franchise competition as a result of 9
the merger.
Mr. Kahal expresses fears that the merger may reduce competitive 10 pressures for UP&L to keep costs minimized.
11 Q. Would you please comment on Dr. Taylor's view that the merger 12 would reduce fringe competition?
' 13 A.
Yes. At page 18, Dr. Taylor claims that PP&L and UP&L compete for 14 loads located near the borders separating their service areas.
At page 19, he 15 uses as an example the competition between PP&L and UP&L for the load of an 16 Exxon gas processing facility in 1983-1984.
While this competition for a retail 17 load which straddled the border between PP&L and UP&L in Wyoming did occur, 18 it was an isolated instance and was noted as such by the Wyoming Public 19 Service Commission (WPSC):
20 The Commission considers this case an uniaue and it would 21 be a mistake for any oublie utility to attemot to use this 22 decision as a steooint stone for the invasion of another's 23 eertificated area. (emphasis in the original) Order of Public 24 Service Commission of Wyoming in Docket No. 9602, Sub 25 13, November 20, 1984.
26 As I pointed out in my direct testimony, PP&L and UP&L are 27 adjacent at only a few areas. This can be seen in Dr. Taylor's Exhibit No.180, 2P (GT-2), which shows that PP&L and UP&L are adjacent only in Western 11 f3 l'n'
L Y*
Exhibli No. 213 Page 60 1
Wyoming. The only possible reduction in fringe area competition would occur in 2
that area and the WPSC made clear in its Order in Docket 9602, Sub.13 that -
3 competition, such as occurred for the Exxon load, would not be well received 4
by the Commission.
Fringe area competition between the merged companies and 5
other investor-owned utilities would not be reduced by the merger.
6 Q. Dr. Taylor, at page 18, also is concerned about the effect on 7
competition between the merged companies and small public agency utilities.
8 Will the merger reduce fringe competition with public agency utilities?
9 A.
No.
There will be no change in fringe area competition between the 10 PP&L/UP&L and public agency utilities due to the merger.
11 Q. Why not?
12 A.
At page 21, lines 1-5, Dr. Taylor claims that the merger "would deny 13 fair and reasonable transmission access to public agency utilities in the 14 Applicants' service areas.
Without such access to economic bulk power supplies, 15 public agency utilities cannot be competitive."
To come to such a conclusion, 16 Dr. Taylor has to assume that the merged companies will not honor existing 17 contracts to wheel preference and other bulk power to public agency utilities.
18 The Applicants have made it clear that they will honor all existing contracts, 19 including those to public agency utilities.
Dr. Taylor gives us no reason to l
20 expect otherwise.
l 21 Q. As an example of the damage to franchise competition, Dr. Taylor, at 22 page 21, refers to UP&L's denial to wheel power from IPC to Washington City l
l 23 over the contract path chosen by Washington City.
Is his example an instance l
24 of harm to competition due to the merger?
25 A.
His example is not a good example for four reasons.
- First, 26 hir. Toph'am and hir. Tucker have now made clear that the merged company will i
i n O l'n'
i.
~
s'.
4 Exhibli No. 213 Page 61 1
wheel to Washington City.
But, second, even it that were not so, there may be 2
no net harm.
If the most economic use of the transmission is being made, less 3
economi6 uses that are denied result from a proper allocation, not harm to 4
competition.
Third. Washington City was offered an alternative contract path.
5 While that path may not be the one that the Washington City would like, it can 6
serve as the basis for negotiation between the Washington City and UP&L. The 7
claim of an adverse impact on competition due to UP&L's not providing the 8
contract path for wheeling that of Washington City desires is premature.
Such 9
a claim should wait until all negotiations are completed and be based on the 10 final outcome.
Fourth, absent the merger it is not certain that UP&L would 11 have been able to provide wheeling over the contract path Washington City 12 desires.
5 13 Q. Would you comment on Mr. Kahal's fear that after the merger UP&L 14 would have a weakened financial imperative to be competitive and that this 15 could result in the UP&L Division being less aggressive in retaining loads and 16 meeting retail competition as the present UP&L Company?
17 A.
Yes. At page 33, lines 18-23 Mr. Kahal contends:
18 After the merger, the present UP&L/PP&L retail-level 19 competition will no longer exist.
If an industrial customer 20 of the new UP&L Division finds its retail rates unattractive 21 and relocates or shifts activities to the PP&L Division, this 22 is largely a matter of indifference to the PacifiCorp 23 shareholders.
From a total company standpoint, little has 24 changed.
To the extent this matters, the merger thus 25 potentially reduces UP&L's incentive to minimize costs and 26 hold down rates.
27 He is correct when he says that to PacifiCorp Oregon's shareholders 28 it matters little whether an industrial customer is located in the UP&L Division J
29 or PP&L Division.
He is not correct that the UP&L Division thereby has a t
30 lessened incentive to minimize costs.
As I testified in my direct testimony, the l'1 e 1 n-
I.
Exhibli No. 213 e
Page 62 1
merged company will continue to face franchise competition as well as industrial 2
location and yardstick competition from other WSCC utilities.
This competition 3
may well be intensified by the merger and provides an incentive for the merged 4
companies to exploit all of the efficiencies of the merger to minimize costs.
5 Mr. Kahal's contention would indicate that the merger would have a perverse 6
effect on UP&L's rates.
This is inconsistent with the proposed rate reductions 7
for UP&L customers.
8 Q. Dr. Landon, are you aware of the fact that several of the witnesses 9
in this proceeding have advocated that the merger be conditioned upon the 10 adoption of either some type of open wheeling policy or set-aside of Il transmission capacity for nonaffiliated companies?
12 A.
Yes, I am.
In my opinion, the merger should not be contingent upon 13 either of these requirements.
14 Q. Would you please explain why it is not necessary to condition the 15 merger on en open wheeling policy?
16 A.
The open wheeling policies advocated in this proceeding would require 17 the merged company to wheel upon request, absent documented reliability 18 reasons, or would generally obligate the company to wheel for certain 19 categories of customers such as those who agree to wheel for the merged 20 company.
The company has already agreed to wheel to the extent that capacity 21 exists, system reliability is not endangered and it is appropriately compensated.
22 An additional requirement to wheel is unnecessary.
In addition the company's 23 policy provides for more valuable interruptible transactions to take place when 24 the company might otherwise use its transmission capacity if payment is made for the cost of foregone oppurtunities.
An open wheeling policy, as advocated 25 t
l 26 by some witnesses, would be less efficient since there would be no pricing l
b 11 e I'n' i
v.
Exhibit No. 213 Page 63 1
mechanism to allow higher value transactions to displace lower value 2
transactions.
3 Q. Other parties have recommended mandatory transmission set-asides 4
for nonaffiliated competitors.
Would you please comment on the advisability of l
5 this approach?
6 A.
Mandatory set-asides, whether a specific amount for a specific 7
competitor or a - general block set-aside for competitors on a first-come basis, 8
will not promote the efficient competitive result.
Transmission charges based 9
on opportunity costs or a split-savings buy-and-sell policy will promote the 10 economically efficient outcome.
More valuable will replace less valuable uses of scarce transmission resources.
The effect of a specific set-aside, however, is 12 likely to foster uses by the parties who have the set-asides even at the expense 13 of more efficient uses by the merging company or by others.
Price is a very 14 good device to ration scarce resources.
15 Q. Do you agree with those intervenors who demand the right to 16 participate in any transmission expansions?
17 A.
No.
An across-the-board policy governing joint participation in 18 expansions is unrealistic.
A workable joint participation agreement generally 19 requires considerable negotiation of many issues, and reflects a balancing of the 20 interests of the various parties.
The number of participants that is practical, I
21 cost a!!ocation, relative entitlements and other terms which must be agreed to 22 in joint ownership will be specific or unique to a particular set of 23 circumstances.
A general mandate would be counterproductive if a goal is to 24 promote the progress of desirable projects.
Forcing many parties to reach joint 25 agreement may in some cases doom the project and in others will occasion 26 substantial delay.
This is particularly true where the circumstances of the n e l'n'
,I
,s.
Exhibit No. 213 e
Page 64 I
potential participants are diverse.
For further relevant discussion, see my 2
article which is part of Exhibit 214, Schedule 8.
i 3
Q. Dr. Landon, does this conclude your rebuttal testimony?
[
4 A.
Yes, it does.
T
)
i l
4 f
l l
i D O l'n' L.
6*
o U.
4 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Utah Power & Light Company
)
PacifiCorp
)
AFFIDAVIT OF PC/UP&L Merging Corporation
)
JOHN H. LANDON Docket No. EC88-2-000
)
District of Columbia
) sr John H. Landon, having been first duly sworn, on oath, deposes and says that he has read his foregoing testimony, and that if asked the questions therein his answers would be as shown, and that the facu contained in said answers are true to the best of his knowledge, information and belief.
g John H. Landon SUBSCRIBED AND SWORN TO BEFORE ME by the said John H. Landon, this ay of Mh/
,19 Y,
G A
Notary Public in and for District of Columbia' Rosalind Browr.
My Commission expires September 30,1989 n e 13a-