SCEG OATT Formula Transmission Rate Filing.pdf - SCANA ...

20091231-0037 FERC PDF (Unofficia1) 12/29/2009 

BRACEWELL 

&.GIULIANI 

Te..s 

New York 

Wahlnpn, 

Connecticut 

Du"'l 

Kozakh.",n 

London 

DC 

George H. (Greg) Williams. Jr. 

Partner 

202.828.5815 0tIice 

202.857.2122 Fax 

greg.wililams@bgllp.com 

Bracewell & Giuliani LLP 

2000 K Street NW 

Suite 500 

washington, DC 

20008-1872 

December 29, 2009 

The Honorable Kimberly D. Bose 

Secretary 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

Re: 

Soutb Carolina Electric & Gas Company 

OA TT Formula Transmission Rate Filing 

Docket No. ERI0-51 to -(0:) 

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SCE&G's OATT Formula Transmission Rate Filing 

Docket No. ERIO- __ 

Page 2 

Description of SCE&G, Background, and Basis for Filing 

SCE&G -- the principal subsidiary of SCANA Corporation -- is an investor owned utility 

engaged in the generation, transmission, distribution and sale of electric power to retail and 

wholesale customers in the state of South Carolina. SCE&G's service territory covers 

approximately 16,000 square miles in central and southern South Carolina, and its transmission 

system consists of approximately 3,500 miles of transmission lines. Since 1996, SCE&G has 

provided open access transmission service pursuant to its OATT, the current version of which is 

on file as SCE&G FERC Electric Tariff, Fourth Revised Volume No.5. 

SCE&G's existing transmission rates, based on a fixed revenue requirement, have been 

on file with the Commission, unchanged, for more than a decade. SCE&G filed its last 

transmission rate case in 1996, and in that filing proposed rates based on a revenue requirement 

for the 1994 calendar test year. 4 The Commission accepted a settlement resolving that rate case 

in April 1999. 5 Since that time, SCE&G's net transmission plant investment has more than 

doubled. 

SCE&G has concluded that its conversion from fixed-revenue-requirement rates to 

Formula Rates is necessary because Formula Rates will better reflect changes in SCE&G's 

transmission revenue requirement, which is particularly critical given that SCE&G expects to 

make substantial investments in its transmission system. 6 SCE&G's proposed Formula Rates 

will allow SCE&G to recover its transmission costs in a timely manner, and so will promote the 

construction of transmission on the SCE&G system and enhance system reliability. SCE&G's 

proposed Formula Rates track both increases and decreases in costs, thereby avoiding the 

necessity for frequent rate adjustment filings, and preventing both over-recovery and underrecovery 

of those costs. Formula Rates will keep SCE&G whole in its cost recovery, and also 

will help ensure that transmission customers pay appropriate rates over time by factoring in cost 

changes that may contribute to reducing the cost-of-service and the resulting rates. 

SCE&G's proposal to adopt Formula Rates is in keeping with Commission case law, 

which encourages use of formula rates. In recent years, the Commission has particularly 

encouraged utilities to adopt formula rates when, as is the case for SCE&G, the utility is 

transmission owners to move from stated rates to formula rates"); Commonwealth Edison Co., 119 FERC 

'\161,238,at P 75 (2007) (same); Trans-Allegheny Interstate Line Co., 119 FERC '\161,219,at P 94 (2007) 

(accepting a proposed transmission formula rate with nominal suspension); Idaho Power Co., 115 FERC 

'\161,281,at P 30 (2006) (nominal suspension ofa proposed change from stated rates to formula rates). 

4 

See SCE&G rate filing in Docket No. ER96-10SS, Feb. 16, 1996. 

6 

South Carolina Electric & Gas Co., 87 FERC '\161,024(1999). 

See the testimony and exhibits of SCE&G witness Mr. Addison, describing the 

investments that SCE&G expects to make in the next decade.



Docket No. ERIO- __ 

Page 3 

considering transmission expansion. In Order No. 679, for example, the Commission stated that 

"formula rates can provide the certainty of recovery that is conducive to large transmission 

expansion programs.,,7 

In an effort to inform its transmission customers about this Formula Rate filing, SCE&G 

conducted a customer outreach process in the winter and spring of 2009. All of SCE&G's 

transmission customers were invited to participate in a general public session, at which SCE&G 

described the proposed Formula Rate filing and entertained questions. In addition, SCE&G 

offered each customer the opportunity to discuss with SCE&G issues of specific relevance to 

each, and three customers availed themselves of those individual discussions. Finally, SCE&G 

posted information about the proposed Formula Rate filing on its OASIS. By these efforts, 

SCE&G offered customers an opportunity to raise and resolve their concerns before this filing 

was made and provided its customers with ample notice of, and explanation for, this filing. 

Introduction 

of Witnesses 

SCE&G supports this rate filing with the testimony of four witnesses: 

White, and Heintz, and Dr. Vilbert. 

Messrs. Addison, 

Mr. Addison addresses three topics: (I) He supports SCE&G's request to utilize a 

formula for the determination of its annual transmission revenue requirement; (2) He explains 

the business and financial risks peculiar to SCE&G that bear upon its credit rating and cost of 

capital; and (3) He supports the cost of capital to be used in SCE&G's filing. 

Mr. White supports recovery of SCE&G's costs incurred pursuing the GridSouth regional 

transmission organization in response to the Commission's mandates in Order No. 2000 and 

subsequent related orders. 

Mr. Heintz supports the formula rate methodology that SCE&G proposes to implement. 

He explains all the components of the formula and supports the population of the formula with 

costs for this rate filing. He explains the protocols for annual adjustments of the rates pursuant to 

the formula. He also explains and supports charging for network transmission service through a 

formula rate, replacing the current load-ratio share methodology. He explains how the formula 

will accommodate future rate incentives that may be granted by the Commission for particular 

7 

Promoting Transmission Investment Through Pricing Reform, Order No. 679, FERC 

Stats. & Regs.' 31,222, at P 386 ("Order No. 679"), order on reh'g, Order No. 679-A, FERC Stats. & 

Regs. , 31,236 (2006) ("Order No. 679-A"), order on reh 'g, 119 FERC , 61,062 (2007). See also New 

York Indep. Sys. Operator, Inc., 109 FERC, 61,372, at P 29 (2004), reh'g denied, III FERC, 61,182 

(2005) (encouraging parties to explore option of formula transmission rates); Allegheny Power Sys. 

Operating Cos., \06 FERC '61,003, at P 32 (2004) (parties to explore option of formula transmission 

rates and noting that the Commission has approved incentive formula rates); So. Calif. Edison Co., 116 

FERC, 61,099, at P 17 (2006) ("formula rates enhance cost recovery"),


SCE&G's OATT Formula Transmission 

Docket No. ERIO- 

Rate Filing 

Page 4 

transmISSIOn projects. Finally, he explains the proposed amortization of the GridSouth costs 

referenced in Mr. White's testimony. 

Dr. Vilbert supports SCE&G's return on common equity (ROE) of 11.5% that will be 

applied to SCE&G's transmission rate base. Although Dr. Vilbert's testimony supports an 11.5% 

return on common equity, in order to ensure no (or nominal) suspension, SCE&G seeks only 

11.3%. 

Description 

of the Formula Rate 

As explained in the testimony of Mr. Heintz, SCE&G's Formula Rates proposal is based 

on the methodology approved by the Commission in several recent proceedings. 8 The formula 

proposed by SCE&G is essentially the same as the formula approved by the Commission in P P L 

Electric Utilities Corp., 125 FERC ~ 61,121 (2008). 

The formula, to be incorporated into Attachment H of SCE&G's OA TT, has three 

components. The first component (which appears at Attachment H of the OATT) is a statement 

that the rates and SCE&G's charges for NITS will be calculated based on the formula. The 

second component (which appears at Appendix A to Attachment H) is the formula itself and 

associated work papers. The third component (which appears at Appendix B to Attachment H) 

consists of a set of protocols that describe how SCE&G will update the formula in future years, 

what the review procedures are, how customer challenges will be resolved, and how any changes 

to the annual rate restatements will be implemented. 

The proposed formula enables SCE&G to calculate the net annual transmission revenue 

requirement for each rate year. Except for the initial, partial rate year, each rate year will be the 

twelve month period beginning June. 1. SCE&G will populate the formula using actual calendar 

year cost data, with limited exceptions. The majority of the actual data inputs are reported 

annually in SCE&G's FERC Form No. 1 filed with the Commission by April 30 th each year. 

SCE&G proposes to use these data to populate the formula each May to produce the NITS and 

PTP transmission service rates that will become effective each June I. SCE&G will submit to 

the Commission annual informational filings containing these data. 

Forecasted plant additions also will be included in the formula and then trued-up after the 

year is over. The true-up between the forecasted and actual net revenue requirement will be 

calculated each subsequent rate year and applied, with interest, as an addition to, or subtraction 

from, the subsequent year's net revenue requirement and resultant rates. 

SCE&G's proposed formula conforms to Commission requirements that certain inputs be 

fixed and unchanging absent the Company's obtaining authorization through a Section 205 filing; 

8 

See, e.g., Baltimore Gas and Electric Co., 115 FERC ~ 61,066 (2006); Duquesne Light 

Co., 118 FERC ~ 61,087 (2007); Commonwealth Edison Co., 119 FERC ~ 61,238 (2007).





PageS 

these inputs are ROE, Post-retirement Benefits other than Pensions (PBOPs), and depreciation 

rates. 9 The annual transmission revenue requirement determined by the formula, divided by the 

12 coincident peak (12 CP) load, will yield the annual charge per MW, which will then be 

converted into a monthly charge. The monthly bill for each NITS customer will be calculated by 

multiplying that monthly charge per MW times the customer's actual use. For PTP service, 

charges for yearly, monthly, weekly, daily and hourly service also will be developed based on 

the results of the formula. The yearly rate for firm PTP service will be the same as the yearly 

NITS rate, with rates for other services derived based on the yearly rate. Rates for PTP 

customers taking short term service will include on-peak and off-peak pricing consistent with 

C 

.. I 10 

omm1SSIOncase aw. 

Formula Rate implementation protocols, included in the OATT, describe how SCE&G 

will update the formula in future years, what the review procedures are, how customer challenges 

will be resolved, and how any changes to the annual rate restatements will be implemented. The 

review procedures prescribe certain periods for (I) customer review of, (2) service of data 

requests and SCE&G responses thereto in connection with, and (3) preliminary and formal 

challenges to, the annually published Formula Rates. The protocols also prescribe certain 

periods for filing a complaint with the Commission, and SCE&G's response thereto, in the event 

formal challenges cannot be resolved by the parties. These procedures do not limit in any way 

SCE&G's right to file to change the formula or its inputs under section 205 of the Federal Power 

Act, or the right of any other party to file a complaint requesting such changes under section 206. 

Return on Equity 

Dr. Vilbert determines the applicable cost of equity using the sustainable growth 

discounted cash flow (OCF) methodology favored by the Commission. II This methodology 

determines the ROE by summing the expected growth rate and the dividend yield (with an 

adjustment for the quarterly payment of dividends) and applying that methodology to a proxy 

group consisting of companies facing risks similar to SCE&G. Following Commission 

precedent,12 Dr. Vilbert selected a proxy group consisting of companies in the region where 

9 

See, e.g., Trans-Allegheny 

denied, 121 FERC 'If 61,009 (2007). 

Interstate Line Co., 119 FERC 'If 61,219, at P 54 (2007), reh'g 

10 

See, e.g., American Electric Power Service Corp., 39 FERC 'If 61,296 (1987). 

11 

E.g., Southern California Edison Co., Opinion No. 445, 92 FERC 'If 61,070 (2000), reh'g 

denied, 108 FERC 'If 61,085 (2004); Consumers Energy Co., Opinion No. 456,98 FERC 'If 62,333 (2002). 

12 

Transmission, 

P 25 (2008). 

See, e.g., Westar Energy, Inc., 122 FERC 'If 61,268, at P 93 (2008); Tallgrass 

LLC, 125 FERC 'If 61,248, at PP 74-75 (2008); Startrans 10, L.L.c., 122 FERC 'If 61,306, at




Page 6 

SCE&G is located. Then, consistent with the Commission's recently articulated guidelines,13 he 

restricted that proxy group based on the credit ratings of the companies in the group, which he 

calls the Restricted Sample. For this Restricted Sample, the median is 11.04% and the midpoint 

is 12.46%. He also used a proxy group that was not restricted by credit ratings, which he calls 

the Full Sample. For the Full Sample, the median is 11.04% and the midpoint is 11.94%. Based 

on the several data points from those two samples, and for the reasons explained below, Dr. 

Vilbert recommends a return on equity for SCE&G of 11.5%. 

He recommends an ROE between the midpoint and median for several reasons. First, the 

nation is in the midst of a serious financial and credit crisis and the cost of capital is higher today 

than prior to this crisis, which suggests that the median should be viewed as conservative. 

Second, the Commission's policy with respect to the use of midpoint vs. median does not appear 

to be settled. 14 Moreover, the Commission's stated basis for the use of the median -- i.e., to 

eliminate extremes in order to capture "central tendencies" of the sample -- is compromised in 

this case because the sample is so small to begin with. It is reasonable, therefore, to look at both 

the midpoints and medians of the sample ranges in making a recommendation. Third, SCE&G's 

circumstances, as testified to by Mr. Addison, suggest it is of higher relative business risk to the 

sample, which the Commission has recognized as requiring upward adjustment. 15 

In the two samples noted above, the midpoints are 90 to 142 basis points higher than the 

median, and suggest that the median is a conservative ROE estimate for the sample, and an ROE 

of 11.5 percent roughly splits the difference between the midpoint and the median under the 

Restricted Sample. For all these reasons, Dr. Vilbert concludes an ROE of 11.5% is justified. 

Although a 11.5% ROE is justified, SCE&G will accept a return on equity of 11.3% -- 

lower than that recommended by Dr. Vilbert -- in order to avoid suspension and hearing. 16 

13 

Westar, 122 FERC ~ 61,268; Potomac-Appalachian Transmission Highline, L.L.C., 122 

FERC ~ 61,188 (2008); Atlantic Path 15, LLC, 122 FERC ~ 61,135 (2008). 

14 

Prior to April 2008, the Commission had consistently relied on the midpoint. See, e.g., 

Consumers Energy Co., 98 FERC ~ 61,333 (2002). In April 2008, the Commission, in two cases (Golden 

Spread Electric Cooperative v. Southwestern Pub. Service Co., 123 FERC ~ 61,047 (2008) (Golden 

Spread), and Virginia Electric Power Co., 123 FERC ~ 61,098 (2008) (VEPCO)), decided to use the 

median. The Commission's departure from its settled use of midpoint to the use of median is subject to 

challenge on rehearing and in numerous pending cases where parties have filed testimony challenging the 

use of median. To date the Commission has not reaffirmed the use of median. In one case decided after 

Golden Spread and VEPCO (Public Service Electric & Gas Company, 124 FERC ~ 61,303, (2008) 

(PSE&G)), the Commission accepted an ROE based on the use of midpoint. 

15 

See PSE&G, 124 FERC ~ 61,303. 

16 

See Central Maine Power Co., 65 FERC 61,192 (1993) (Commission offers no hearing in 

exchange for lower rate ofretum on equity.)




Page 7 

Recovery of GridSouth Costs 

SCE&G seeks recovery of the costs that it incurred attempting to form a regional 

transmission organization (RTO), i.e., the GridSouth Transco, LLC (GridSouth), in direct 

response to Commission mandates in Order No. 2000 17 and subsequent related orders. 

Responding to Order No. 2000, SCE&G, along with Duke Energy Corporation and Carolina 

Power & Light Company, filed an application seeking approval of GridSouth. In March 2001, 

the Commission accepted the GridSouth filing and granted GridSouth provisional RTO status, 

subject to further filings. 18 SCE&G (and the other GridSouth proponents), beginning in the Fall 

of 2000, initiated a comprehensive effort to bring GridSouth into operation. Land was procured 

and a facility constructed in Fort Mill, South Carolina. Operating systems and related hardware, 

some staffing, software, other system supports, and the related design and installation of these 

systems, were contracted for and pursued. 

Meanwhile, in July 200 I, the Commission issued an order directing all of the entities in 

the various RTO proceedings in the Southeastern United States to engage in good faith 

negotiations to develop a plan for a single Southeastern RTO.19 According to the Commission's 

order, this mediation effort did not supersede GridSouth efforts; rather, the GridSouth and 

mediation efforts ran in parallel. In response to the Commission's mediation directive, SCE&G, 

along with the other GridSouth proponents, participated in the complex mediation that followed. 

Ultimately, however, the GridSouth effort did not result in an RTO, despite the good faith 

and substantial efforts of the parties. Nor was any consensus reached on creating a Southeastern 

regional RTO. In October, 2005, the Commission formally terminated the GridSouth 

procee d· mg. 

20 

In an order addressing the accounting treatment of GridSouth expenditures,21 the 

Commission authorized deferral of the RTO formation related costs (including carrying costs) 

17 

Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs. ~ 31,089 

(1999), order on reh 'g, Order No. 2000-A, FERC Stats. & Regs. ~ 31,092 (2000), afJ'd sub nom. Public 

Utility District No.1 o/Snohomish County. Washington v. FERC. 272 F.3d 607 (D.C. Cir. 2001). 

18 

Carolina Power & Light Company, et al., 94 FERC ~ 61,273 (2001). 

19 

See Regional Transmission Organizations, 96 FERC ~ 61,066 (2001). 

20 

GridSouth Transco, L.L.C, 113 FERC ~ 61,053 (2005). 

21 

Duke Energy Corp., 94 FERC ~ 61,080 (2001) (GridSouthAccounting 

Order).



Docket No. ERlO- 


Page 8 

associated with establishing GridSouth. The Commission emphasized that "we want to assure 

utilities that they will not be disadvantaged by participating in an RTO.,,22 

SCE&G now seeks recovery of the RTO development costs that it incurred in following 

the Commission's directives. This is the appropriate proceeding for recovery of GridSouth costs. 

This is the first transmission rate case SCE&G has filed since the cancellation of the GridSouth 

Project. Moreover, the Commission has specifically rejected challenges to recovery of RTO 

formation costs on the basis that the Compani could have sought and the Commission could 

have authorized earlier recovery of these costs. 3 Recovery of these prudently incurred, just and 

reasonable costs is appropriate. 

The Commission's policy of allowing utilities to recover RTO development costs, 

originally set forth in Order No. 2000, is now well-established in a variety of cases, including 

cases when the RTO development efforts were ultimately unsuccessful and the RTO in question 

was not formed. 24 In Entergy25 and Idaho Power,26 as in the case of GridSouth, the transmission 

providers endeavored to create an RTO, but were ultimately unsuccessful. As the Commission 

explained in Entergy, despite the lack of success in establishing an RTO, recovery of RTO 

development costs is consistent with Commission policy. Denying transmission providers the 

ability to recover start-up costs in unsuccessful efforts "would only serve to make ... similarly 

situated entities less likely to pursue the development of an RTO.,,27 There have been no cases 

that question the Commission's policy of allowing recovery ofRTO development costs. 

The Commission has found RTO development costs properly supported if the applicant 

sufficiently demonstrates both the nature of the costs and how they were incurred in furtherance 

of RTO development. 28 Through the testimony and exhibits of Mr. White, SCE&G provides 

22 

Id. at 61,369 (quoting Order No. 2000 at 31,172-73). 

23 

Virginia Electric Power Co., 125 FERC '\161,391, at P 29-31 (2008), reh'g denied, 128 

FERC '\161,026, at P 29 (2009). 

24 

Entergy Services, Inc., 117 FERC '\161,320 (2006); Idaho Power Co., 123 FERC '\161,104 

(2008). See also Northeast Utilities Service Co" 121 FERC '\161,308, at P 20 (2007) ("the Commission 

has allowed full rate recovery of RTO formation costs, including costs associated with efforts that have 

not led to RTO formation"), citing Alliance Cos., 99 FERC '\161,105 (2002); Illinois Power Co., 108 

FERC '\161,258 (2004); and Entergy, 117 FERC '\161,320. 

25 

Entergy, 

117 FERC '\161,320. 

26 

Idaho Power, 123 FERC '\161,104. 

27 

Entergy, 117 FERC '\I 61,320, at P 21. 

28 

Virginia Power, 125 FERC '\161,391, at P 28, order on reh'g, 128 FERC '\161,026, at P 4.




Page 9 

such support for the recovery of SCE&G's GridSouth expenditures. In addition, the GridSouth 

costs include a carrying charge. Commission caselaw supports recovery of such carrying 

charges. 29 

In sum, the formation of RTOs was a major policy objective of the Commission during 

the time period in which the GridSouth costs were incurred. SCE&G and the other GridSouth 

entities sought to comply with that Commission initiative and incurred prudent and legitimate 

costs in doing so. The Commission has allowed transmission providers to recover RTO 

formation costs in these circumstances. SCE&G requests that the Commission do so here as 

well. 3o 

Initial Revenue Requirement 

Subject to true-up, the first (partial) year annual transmission revenue requirement for 

NITS under the proposed formula is approximately $91.5 million. The $46.1 million (101 %) 

increase in the revenue requirement relative to the $45.4 million revenue requirement approved 

in SCE&G's last rate case, based on a 1994 test year, is largely due to the increase in rate base as 

a result of numerous investments that SCE&G has made in transmission related plant. For 

example, the projected gross plant balance in the first year of the formula rate represents an 

increase of approximately $468 million above the plant balance at the end of 1994. The effect of 

this increase on SCE&G's transmission customers is detailed in the (combined) Statement 

BG/BH included in this filing. 

Transmission Construction Program 

The Energy Policy Act of 2005 and Commission Order No. 679 have stressed the 

importance of the development of new transmission infrastructure. SCE&G witness Mr. 

Addison describes the substantial transmission expansion expected over the next decade. The 

Formula Rates proposed in this filing will help facilitate these major investments. Although 

SCE&G is not seeking explicit rate incentives in connection with this transmission expansion, 

SCE&G's witnesses Mr. Addison and Dr. Vilbert demonstrate that the Commission should 

29 

Virginia Power, 128 FERC ~ 61,026, at PP 43-45 (where the Commission rejected a 

challenge to recovery of carrying charge for RTO expenditures, reasoning that: "Carrying charges reflect 

the time value of money. . .. Recovery of these charges is necessary to ensure that [the utility 1 receives 

compensation for the costs that it has incurred and the time value of not recovering these costs earlier"). 

30 

GridSouth costs are included in SCE&G's proposed Formula Rates at Appendix A, lines 

57 and 65. As discussed in the testimony ofMr. Heintz, SCE&G proposes to amortize these costs for five 

years, beginning June 1,2010.




Page 10 

consider this transmission expansion in its overall determination of SCE&G's risk and its return 

on equity. 

Because SCE&G may seek rate incentives in the future, the proposed formula contains a 

placeholder to accommodate such incentives if granted at some future time by the Commission. 

Consistent with Commission case law, the placeholder has been set at zero 3J If in the future 

SCE&G seeks authorization for incentives, SCE&G will at that time apply under section 205 to 

replace the zero values in the placeholder with the approved amounts. 

The Formula Rate Should be Approved With No, or Nominal, Suspension and Without 

Hearing 

In an effort to encourage the adoption of formula rates, the Commission has routinely 

permitted such formula rate filings to become effective with only nominal suspension. 32 A 

similar result is warranted here. Customers are protected from paying excessive rates because the 

formula rates proposed here are modeled after formula rates previously approved by the 

Commission. The requested Formula Rates include implementation protocols, familiar to the 

Commission, that preserve customers' rights to challenge the Formula Rates. 

Moreover, SCE&G is willing to accept a return on equity lower than that justified by Dr. 

Vii bert -- a respected cost of capital expert, who follows closely the Commission's preferred 

methodology for determining ROE -- in order to avoid suspension and hearing. 

Because the instant filing adheres closely to Commission precedent, because the interests 

of customers are protected, and because SCE&G is willing to forgo an increment of return 

otherwise justified, SCE&G requests that the Commission approve this filing with no, or 

nominal, suspension and without setting the filing for evidentiary hearing. Should the 

Commission nevertheless set the matter for hearing, SCE&G requests Commission approval of 

Dr. Vii bert's recommended return on equity,33 and further requests that the Commission 

narrowly circumscribe the issues set for hearing (not permitting parties to litigate Formula Rate 

provisions previously approved by the Commission in other proceedings). 

31 

Arizona Public Service Co., 120 FERC ~ 61,262, at P 26 (2007); American Electric 

Power Service Corp., 120 FERC ~ 61,205, at P 36 (2007); San Diego Gas & Electric Co., 118 FERC 

~ 61,073, at P 23 (2007). 

32 

See note 3 supra. The extent of the rate increase should not be a factor in the 

Commission's suspension determination in this case. The rate increase in this case is a function of the 

extraordinary length of time since SCE&G's last rate change (over 13 years). SCE&G should not be 

penalized with a rate suspension just because it has not filed a rate increase in such a long time. 

33 

SCE&G only agrees to the 11.3% return on equity if the Commission does not set this 

case for hearing. See footnote 16, supra.





Page 11 

Contents of Filing 

This filing consists of an original and five copies of the following: 34 

• This transmittal letter; 

• Clean tariff sheet nos. 9 (Table of Contents), 143-44 (Section 34.1), 166-167-A 

(Schedule 7), 168-170-A (Schedule 8) and 214-214-CC (Attachment H) for 

SCE&G's FERC Electric Tariff, Fourth Revised Volume No.5. See Appendix A 

hereto; 

• Redlined tariff sheet nos. 9 (Table of Contents), 143-44 (Section 34.1), 166-167- 

A (Schedule 7), 168-170-A (Schedule 8) and 214 (Attachment H) for SCE&G's 

FERC Electric Tariff, Fourth Revised Volume No.5. See Appendix B hereto;35 

• Exhibits SCE-1 through SCE-5, the testimony and exhibits ofMr. Addison; 

• Exhibits SCE-6 and SCE-7, the testimony and exhibit ofMr. White; 

• Exhibits SCE-8 through SCE-12, the testimony and exhibits of Mr. Heintz 

(including Statements BG and BH); and 

• Exhibits SCE-13 and SCE-16, the testimony and exhibits of Dr. Vii bert. 

Request for Waivers 

To the extent that waivers of the Commission's regulations are necessary, SCE&G 

requests such waivers as are appropriate to ensure this filing complies with the requirements of 

Part 35 of the Commission's rules and regulations. In particular, SCE&G requests necessary 

waivers of the Commission's rate filing regulations, in 18 C.F.R. § 35.13, related to the provision 

of Period I and Period II data, including waiver of the requirements pertaining to the filing of 

costs statements, waiver of the full Period I-Period II data requirements, waiver of the 

requirement in Section 35.13(c)(6) to submit attestation concerning Period II submissions, and 

waiver of the requirements in Section 35. 13(a)(2)(iv) to determine if and the extent to which a 

34 

See Quick Reference guide for paper submissions, revised 12114/2009, posted on the 

Commission's website, at http://www.ferc.gov/docs-filinglformslfileguide.pdf. 

35 

See 18 C.F.R. § 35.10 (b) (2009). SCE&G prepared this redline by using "Deltaview" 

software. To the extent the redlining affected the tariff sheet pagination, SCE&G requests waiver of the 

redline requirement for that pagination. In addition, original tariff sheet nos. 214-A through 214-CC 

submitted herein contain the formula rate. These sheets are new tariff sheets and a redline would simply 

reflect that these tariff sheets are new. Hence, SCE&G requests waiver of the requirement to submit 

redlined tariff sheets for original tariff sheet nos. 214-A through 214-CC.





Page 12 

proposed change constitutes a rate increase based on Period I-Period II rates and billing 

determinants. The Commission has consistently granted such waivers 36 and should do so here. 

The testimony and exhibits accompanying this filing, together with SCE&G's publicly-available 

FERC Form 1 information, provide ample support for the reasonableness of the proposed 

formula rate. 

SCE&G further requests that the Commission grant such waivers as necessary to allow 

these proposed tariff changes to be accepted and made effective as requested. 

Miscellaneous 

No agreement is required by contract for this rate filing. There are no costs included in 

this filing that have been alleged or adjudged in any administrative or judicial proceeding to be 

illegal, duplicative, or unnecessary costs, nor has any expense or cost been demonstrated to be 

the product of discriminatory employment practices, within the meaning of 18 C.F.R. 

§ 3S.13(d)(3). 

36 

fTC Great Plains. LLC, 126 FERC '\l61,223, at P 121 (2009); Tal/grass Transmission, 

125 FERC '\l61,248, at P 95; Oklahoma Gas & Electric Co., 122 FERC '\l61,071, at P 41 (2008); 

Commonwealth Edison Co., 119 FERC '\l61 ,238, at PP 92-94 (2007).



Docket No. ERlO- 


Page 13 

Communication 

and Service 

Communications regarding this filing should be addressed to the following individuals, 

who should be entered on the official service lists 37 maintained by the Secretary of the 

Commission for each docket established with respect to any of the documents filed with this 

letter: 

Catherine D. Taylor 

South Carolina Electric & Gas Company 

220 Operations Way, MC-C222 

Cayce, South Carolina 29033 

Tel: (803) 217-9356 

Fax: (803) 327-9336 

cdtaylor@scana.com 

Charles A. White 


220 Operations Way, MC-J35 

Cayce, South Carolina 29033 

Tel: (803) 217-2018 

Fax: (803) 933-7242 

cwhite@scana.com 

George H. (Greg) Williams, Jr. 

Bracewell & Giuliani LLP 

2000 K Street, N.W. 

Suite 500 

Washington, D.C. 20006-1872 

Tel: (202) 828-5800 

Fax: (202) 223-1225 

greg.williams@bgllp.com 

A copy of this filing has been sent to the Public Service Commission of South Carolina 

and to each of SCE&G's transmission customers who have purchased transmission service 

within the last three years. 

37 

service list. 

SCE&G requests waiver of the Commission's regulations to include three people on the



Docket No. ERI0- 


Page 14 

Thank you for your assistance in this matter. If there are any questions, please contact 

the undersigned. 

Respectfully submitted, 

South Carol' a Electric & Gas ompany 

Bracewell & Giuliani 

2000 K Street, N.W. 

Suite 500 

Washington, D.C. 20006-1872 

Attorneys for 


Dated: December 29, 2009


UNITED STATES OF AMERICA 

BEFORE THE 

FEDERAL ENERGY REGULATORY COMMISSION 


) 

) 

) 

Docket No. ERIO- _ 

CERTIFICATE 

OF SERVICE 

Pursuant to Rule 2010 of the Commission's Rules of Practice and Procedure, I hereby 

certify that I have this day served a copy of the foregoing document on the Public Service 

Commission of South Carolina and on each of SCE&G's transmission customers who have 

purchased transmission 

service within the last three years. 

Dated at Washington, D.C., this 29th day of December, 2009. 

J. Bartus 

B acewell & Giuliani LLP 

00 K Street, NW, Suite 500 

Washington, DC 20006-1872 

(202) 828-5800 

Attorney for 

South Carolina Electric & Gas Company


SOUTH CAROLINA ELECTRIC & GAS COMPANY 

DOCKET ERIO- -000 

APPENDIX A TO DECEMBER 29, 2009 FILING 

CLEAN TARIFF SHEETS



or its designated agent 

FERC Electric Tariff 

Fourth Revised Volume No.5 

Revised Open Access Transmission Tariff 

First Revised Sheet No.9 

Superseding Original Sheet No.9 

Fonn Of Service Agreement For Finn Point- To-Point Transmission Service 

............................................................................................................................. 176 

ATTACHMENT A-l 180 

Fonn Of Service Agreement For The Resale, Reassignment Or Transfer Of 

Point- To-Point Transmission Service 180 

ATTACHMENTB 184 

Fonn Of Service Agreement For Non-Finn Point- To-Point Transmission 

Service 184 

ATTACHMENT C 186 

Methodology To Assess Available Transfer Capability 186 

ATTACHMENTD 198 

Methodology for Completing a System Impact Study 198 

ATTACHMENTE 203 

Index Of Point- To-Point Transmission Service Customers 203 

ATTACHMENTF 209 

Service Agreement For Network Integration Transmission Service 209 

ATTACHMENTG 211 

Network Operating Agreement 211 

ATTACHMENTH 214 

Rate For Network Integration Transmission Service 214 

Appendix A 214-A 

Appendix B 214-V 

ATTACHMENT I... 215 

Index Of Network Integration Transmission Service Customers 215 

ATTACHMENT J 216 

Procedures for Addressing Parallel Flows 216 

ATTACHMENT K 217 

Transmission Planning Process 217 

Appendix K-2 238 

Appendix K-3 239 

Southeast Inter-Regional Participation Process 239 

ATTACHMENT 1. 270 

Creditworthiness Procedures 270 

Issued by: Charles A. White 

Vice President - Electric Transmission 

Issued on: December 29, 2009 

Effective: March 1, 2010







First Revised Sheet No. 143 

Superseding Original Sheet No. 143 

Utility Practice, also may Curtail Network Integration Transmission 

Service in order to (i) limit the extent or damage of the adverse condition(s) 

or disturbance(s), (ii) prevent damage to generating or transmission 

facilities, or (iii) expedite restoration of service. The Transmission 

Provider will give the Network Customer as much advance notice as is 

practicable in the event of such Curtailment. 

Any Curtailment of Network 

Integration Transmission Service will be not unduly discriminatory relative 

to the Transmission Provider's use of the Transmission System on behalf of 

its Native Load Customers. 

The Transmission Provider shall specifY the 

rate treatment and all related terms and conditions applicable in the event 

that the Network Customer fails to respond to established Load Shedding 

and Curtailment procedures. 

34. Rates and Charges 

The Network Customer shall pay the Transmission Provider for any Direct 

Assignment Facilities, Ancillary Services, and applicable study costs, consistent 

with Commission policy, along with the following: 

34.1 Monthly Demand Charge: 

The Network Customer shall pay a monthly Demand Charge, which shall 

be determined by multiplying its Monthly Network Load pursuant to 

Section 34.2 by the rate specified in Attachment H. 



Issued on: December 29. 2009 

Effective: March 1,2010









34.2 Determination of Network Customer's Monthly Network Load: 

The Network Customer's monthly Network Load is its hourly load 

(including its designated Network Load not physically interconnected with 

the Transmission Provider under Section 31.3) coincident with the 

Transmission Provider's Monthly Transmission System Peak. 

34.3 Determination of Transmission 

Transmission System Load: 

Provider's 

Monthly 

The Transmission Provider's monthly Transmission System load is the 

Transmission Provider's Monthly Transmission System Peak minus the 

coincident peak usage of all Firm Point-To-Point Transmission 

Service 

customers pursuant to Part II of this Tariff plus the Reserved Capacity of all 

Firm Point- To-Point Transmission Service customers. 

34.4 Redispatch Charge: 

The Network Customer shall pay a Load Ratio Share of any redispatch 

costs allocated between the Network Customer and the Transmission 

Provider pursuant to Section 33. 

To the extent that the Transmission 

Provider incurs an obligation to the Network Customer for redispatch costs 




Effective: March I, 2010









SCHEDULE 7 

Long-Term Firm and Short-Term Firm Point-To-Point 

Transmission Service 

1) Yearly, Monthly, Weekly, and Daily Delivery: The rates for Yearly Delivery, 

Monthly Delivery, Weekly Delivery, Daily Delivery for On-Peak Days, and Daily 

Delivery for Off-Peak Days are derived from the Formula, which is set forth in 

Appendix A to Attachment H of this Tariff ("Appendix A"). The rates will be 

updated annually and posted on SCE&G's OASIS in accordance with the Formula 

Rate Implementation Protocols set forth in Appendix B to Attachment H of this 

Tariff. 

The Transmission Customer shall compensate the Transmission Provider each 

month for Reserved Capacity at the sum ofthe applicable charges set forth below: 

a) Yearly Delivery Charge: the Rate for Yearly Delivery (i.e., the amount 

shown on Appendix A) times the number of Megawatts (ttMWstt) of 

Reserved Capacity for the year divided by 12. 

b) Monthly Delivery Charge: the Rate for Monthly Delivery (i.e., 1112th of 

the amount shown on Appendix A) times the number of MWs of 

Reserved Capacity for the month. 






SouthCarolinaElectric& GasCompany 

or itsdesignatedagent 

FERCElectricTariff 

FourthRevisedVolumeNo.5 

RevisedOpenAccessTransmissionTariff 

FirstRevisedSheetNo. 167 

SupersedingOriginal SheetNo. 167 

c) Weekly Delivery Charge: the Rate for Weekly Delivery (i.e., l/S2 nd of 

the amount shown on Appendix A) times the number of MWs of 

Reserved Capacity for the week. 

d) Daily Delivery Charge: 

On-Peak: The Rate for On-Peak Daily Delivery (i.e., l/S th of the 

Rate for Weekly Delivery (shown in subpart (c) above» times the 

number ofMWs 

of Reserved Capacity for the day. 

Off-Peak: The Rate for Off-Peak Daily Delivery (i.e., l/7 th of the 

Rate for Weekly Delivery (shown in subpart (c) above» times the 

number of MWs of Reserved Capacity for the day. 

The total charge in any week, pursuant to a reservation for Daily Delivery, 

shall not exceed the Rate for Weekly Delivery, specified in subsection (c) 

above, times the highest amount in MWs of Reserved Capacity in any day 

during such week. 

2) Definition of On-Peak and Off-Peak Days: For Daily Delivery: On-Peak Days 

are Monday through Friday, and all other days are Off-Peak Days. 

3) Discounts: Three principal requirements apply to discounts for transmission 

service as follows: (1) any offer of a discount made by the Transmission Provider 

must be announced to all Eligible Customers solely by posting on the OASIS; (2) 

any customer-initiated requests for discounts (including requests for use by one's 

Issuedby: CharlesA.White 

VicePresident- ElectricTransmission 

Issuedon: December29, 2009 

Effective:March1,2010







Original Sheet No. 167-A 

wholesale merchant or an Affiliate's use) must occur solely by posting on the 

OASIS; and (3) once a discount is negotiated, details must be immediately posted 

on the OASIS. For any discount agreed upon for service on a path, from point(s) 

of receipt to point(s) of delivery, the Transmission Provider must offer the same 

discounted transmission 

service rate for the same time period to all Eligible 

Customers on all unconstrained transmission paths that go to the same point(s) of 

delivery on the Transmission System. 

4) Resales: The rates and rules governing charges and discounts stated above shall 

not apply to resales of transmission service, compensation for which shall be 

governed by section 23.1 of the Tariff. 













SCHEDULE 8 

Non-Firm Point-To-Point Transmission Service 

1) Monthly, Weekly, Daily, and Hourly Delivery: The rates for Monthly Delivery, 

Weekly Delivery, Daily Delivery for On-Peak Days, Daily Delivery for Off-Peak 

Days, Hourly Delivery for On-Peak Hours, and Hourly Delivery for Off-Peak 

Hours are derived from the Formula, which is set forth in Appendix A to 

Attachment H of this Tariff (nAppendix An). The rates will be updated annually 

and posted on SCE&G's OASIS in accordance with the Formula Rate 

Implementation Protocols set forth in Appendix B to Attachment H of this Tariff. 

The Transmission Customer shall compensate the Transmission Provider for Non- 

Firm Point-To-Point Transmission Service up to the sum of the applicable charges 

set forth below: 

a) Monthly Delivery Charge: The Rate for Monthly Delivery (i.e., lI12'h 

of the amount shown on Appendix A) times the number of Megawatts 

("MWs") of Reserved Capacity for the month. 

b) Weekly Delivery Charge: The Rate for Weekly Delivery (i.e., 1I52 nd of 

the amount shown on Appendix 

A) times the number of MWs of 

Reserved Capacity for the week. 













c) Daily Delivery Charge: 

On-Peak: 

The Rate for On-Peak Daily Delivery (i.e., lISth of the 

Rate for Weekly Delivery (shown in subsection (b) above» times the 

number ofMWs of Reserved Capacity for the day. 

Off-Peak: 

The Rate for Off-Peak Daily Delivery (i.e., 117th of the 



The total charge in any week, pursuant to a reservation for Daily Delivery, 

shall not exceed the Rate for Weekly Delivery, specified in subsection (b) 

above, times the highest amount in MWs of Reserved Capacity in any day 

during such week. 

d) Hourly Delivery Charge: The basic charge shall be that agreed upon by 

the Parties at the time this service is reserved and in no event shall exceed: 

On-Peak: 

the Rate for On-Peak Hourly Delivery (i.e., 1I16 th of the 

Rate for On-Peak Daily Delivery (shown in subsection (c) above» 

times the number ofMWs of Reserved Capacity for the hour. 

Off-Peak: 

the Rate for Off-Peak Hourly Delivery (i.e., 1I24thof the 

Rate for Off-Peak Daily Delivery (shown in subsection (c) above» 

times the number ofMWs of Reserved Capacity for the hour. 













The total charge in any day, pursuant to a reservation for Hourly Delivery, 

shaH not exceed the Rate for On-Peak Daily Delivery, specified in 

subsection 

(c) above, times the highest amount in MWs of Reserved 

Capacity in any hour during such day. 

In addition, the total charge in any 

week, pursuant to a reservation for Hourly Delivery, shaH not exceed the 

Rate for Weekly Delivery, specified in subsection (b) above, times the 

highest amount in MWs of Reserved Capacity in any hour during such 

week. 

2) Definition of On-Peak and Off-Peak Days and Hours: For Daily and Hourly 

Delivery: On-Peak Hours begin at 7 a.m. Eastern Prevailing Time and end at 11 

p.m. Eastern Prevailing Time Monday through Friday, and all other hours are Off- 

Peak Hours; On-Peak Days are Monday through Friday, and all other days are 

Off-Peak Days. 


service as follows: (1) any offer of a discount made by the Transmission Provider 

must be announced to all Eligible Customers solely by posting on the OASIS; (2) 



OASIS; and (3) once a discount is negotiated, details must be immediately posted 

on the OASIS. For any discount agreed upon for service on a path, from point(s) 




Effective: 

March I, 20 I0







Original Sheet No. l70-A 


discounted transmission 

service rate for the same time period to all Eligible 


delivery on the Transmission System. 

4) Resales: The rates and rules governing charges and discounts stated above shall 

not apply to resales of transmission 

service, compensation for which shall be 














ATTACHMENT 

H 

Rate For Network Integration Transmission Service 

I. The rate for Network Integration Transmission Service shall be the rate (expressed 

in $/MW-year) set forth in Appendix A hereto, divided by 12. The rate for 

Network Integration Transmission Service will be updated annually and posted on 

SCE&G's OASIS in accordance with the Formula Rate Implementation Protocols 

set forth in Appendix B hereto. 

2. The Formula in Appendix A hereto, and resultant Network Integration 

Transmission Service rate, shall be effective until amended by the Transmission 

Provider or modified by the Commission. 

3. All quantities used in calculating the Network Customer's Network Load and 

Transmission Provider's Monthly Transmission System Peak shall be adjusted to 

the Transmission System input level, i.e., shall include the transmission capacity 

amount associated with any applicable losses. As a result, the Customer's load, as 

metered at the Point(s) of Delivery (transmission exit level), will be increased 

using the Real Power Loss factor shown in Section 28.5 of this Tariff to bring the 

Customer's load to the generation level. 











Original Sheet No. 214-A 

APPENDIX A TO ATTACHMENT H 

FORMULA RATE 









Fourth Revised Volume No_ 5 


Original Sheet No_ 214-B 

APpendix 

A 

,.. 

Wall" & S.I~ry Allocation Factor 

Transmi •• ion Wa~es Expense 

p3&4.21.b 

Total wages Expense 

p3~.28b 

Les. A&G We es Ex ense 

354.27b 

Total (Line2 - 3) 

Line 114 

Electric Plant in ServiC







Original Sheet No. 214-C 

Construction Wort 1ft Proo .... (CWIP) 

39 CWIP (we'Shied by monthS a'p"oted 10 be placed in service) 

40 Construction Work in PrOOf.... T•• n.... i.. ion 

(Note D) Attachment 6 

(Line 39) 

Accumul .... d Oflerred Income Tues 

41 AOIT "", 01 FASB 106 ~nd log 

42 Accumulatecated 

52 Tran.mission Materials &. Su lies 

53 Total Materials &. SupplieS AllocMedto Transml .. lon 

(Note A) 

p227.16c 

Line 5 0,0000% 

(Line 49' 50) 

227.80 

(U""S1 + 52) 

Cash Working Capital 

t;4 Operabon & Maintenance Expense 

(liM 84) 

• 116 125% 

..~,7A'".O ... ==.C.=o~',=._==mO.="=.,=---------------------------------------~~07~-----------------------"~ 

(line 54' 55) 

~ ';C=C:",~~:~I:hCW~O=.=,=~=,~.O 

57 Unrecovered DeIefTed GrldSoL/th Costa 

(Note QJ Attachment 5 

Network Credits 

Outstanding 58 NelwrI





Fourth Revised Volume No 5 


Original Sheet No_ 214-D 

" 

.. Tetal 

We 

General 

" 

" 

Depreciation E~pen .. 

Tr.... mlnion Depreciation E~p.",.... (Note N) p336.7b 

Gene,al Plant Deprl!(:iation· E"ct,1C Only (Note A artd Attachment N) 5 

Intan~ible Plant Amortization - Electric Onl~ INoteA! Attachment 5 

(Linaae_lIl) 

e& Sala AllocatIon Factor Line 5 0.0000% 

Dep.ecl.tlon Allocooled to Transmission (Line 88' 89) 

Common Plant Depreciation _ Electric Only Attachment 5 

INote A and N) 

Common Plant Amortization - Electric On1r {NOleAl AttachmentS 

Total (Line 91 • 92) 

wa e & Sala AliO







Original Sheet No. 214-E 

Income To R.te5 

127 FIT=Federallncome Ta>







Original Sheet No, 2l4·F 

,- 

A Eledricpcno.nonly 

B 

ExcludeConsn.ction W"'" In Prog-= 

C Transmissioo Portioo Only 

D C"",_ wm. in Progress (CWIPIIS .. tat' .... unbltile C""""issiDn Or""". change 

E .... Reguiai>ry Carrnissinn E___ 

F Salelyrelaled lct!:IIo.. olo .. )'9"O







Original Sheet No. 214-G 

South Carolina Electric & Gas Company (SCEG) 

Attachment 1 - Accumulated Deferred Income Taxes (ADIT) Worksheet 

Only 

Transmission 

Re/Bted 

PI.nt 

Related 

ADfT_ 282 

ADIT-283 

ADIT·190 

Subtotl!li 

Wages & Salary Allocstor 

Gross Plant Allocstor 

All Transmission 100% 

ADIT Allocated to Transmission 

0.0000% 

o 

o 

o 

o 

o 

o 

o 

0.0000% 

o 

o 

o 

COlumn C AOIT ~elTl5 (below) relate ontyto Non·Electric Operations (e,g~ Gas) OR Production OR Items NOT included in the AOIT calculation above 

COlumn C amoum lotals 0 

Check total- Agrees to Recon. (Attachment 1-2) 

o 

Issued by Charles A White 


Issued on December 29, 2009 








Original Sheet No. 214-H 

Attachment 1- Accumulated Deferred Income Taxes (ADIT) Worksheet 

ADfT.190 

A B C 

ProductiOll 

Or Other 

D 

Only 

Tnmsm/ssion 

E 

Plant 

F G 

Total Relllt9d R~I~ed Relt1ted Rellilted .Iustlflcatlon 

Add Pension and FAS 158 from Ace! 283 0 

Subtotal· 234 0 0 0 0 0 

Less FASB 109 Above if not 

"",,"" 

0 0 0 0 0 

Total 0 0 0 0 0 

Instructions for Accounll90: 

1. ADtT items related oolylo Man·EIectric Operations (e.g., ~s, Water. Sewer) or PrOOJetion are directly assigned 10 Column A 

2. ADIT items related onlylo Transmission are directly assigned to Column 8 

3. AOIT items related Plant and not in ColImrr.; A & B Ire directly assigned to Column C 

4, ADIT items related to Labor and not ., Columns A .. B are directly assiQOOd to CoILmli 0 

5. Deferred Income taxes arise when Items are included in taxable 'ncome In different periods than they are included in rates Iherefore, if the item giving rise to the AOrY i5 not 

included inthe formula, the associated ADIT lmouni shall be excluded 

Issued by· Charles A. White 


Issued on December 29. 2009 






Fourth Revised Volume NO.5 


Original Sheet No 214-1 

Atulchment 1•Accumuillted Deferred Income Taxes (ADlr) WorKsheet 

ADIT- 282 

A B C 

Production 

0."",,, 

o 

Only 


E F G 

P~nt 

Total ReI~ R ..... Reillted Reillted JustifiClltion 

Subtotal- 75 •• 0 0 0 0 0 

less FASB109 Above ifno! 0 0 0 0 0 

less FASB 106 Above if not .., """"" 

""""" 

0 0 0 0 0 

lmal 0 0 0 0 0 

Instructions 

for Accourlt ill: 

1. ADIT items related OIIlylo Non·EIeebic Operations (e.g .• Gas. Water, Sewer) or Productioo are directly assigned to Column A 

2. ADIT items related only to TIlmsmission are directly assigned 10 CoILmIl B 

3. ADIT items related Plant and not in CoUnllS A & B are directly assigned to CoiLmln C 

4. AOIT items related 10 labor and not in Columns A & B are directly assigned to CokImn D 

5. 0efeITed income taxes arise when items are included in taxable income in different periods than they are included in rates therefore, if the ~em giving rise 10 the ADIT is not 

included in the fonnul.il, the associated ADIT amount shalille excluded 

Issued by' Charles A. White 







FERC J;lectric Tariff 



Original Sheet No_ 214-J 

Attachment 1- Accumulated Deferred Income raxes (ADI7J Worksheet 

ADfT·283 

A B C 

ProductJon 

Or Other 

o 

Only 


E F G 

Plant 

Total Rel$er;I Refilled Re/sted ReI~_f#i u /fiest/on 

Transfer Pension E and FAS 15810 Acct 190 0 

77 0 0 0 0 0 

""""". 

less FASB 109 Above if not ralel ,~... 0 0 0 0 0 

Less FASB 106 Above if IlOl ratel ,~ 0 0 0 0 0 

Total 0 0 0 0 0 

Instructions fDr Account 283: 

1. AOIT items related only to Non-Electric Operations (e.g•• Gas, Water. Sewer) or Production are directly assigned 10 Column A 

2. ADIT items related only 10 Transmission are directly assigned 10 CoILmn B 

3, ADIT items related Plant and not in Columns A & B are directly assigned to Column C 

4. ADIT items related to labor and not in CoIuImS A & B are diredly assigned 10 Column D 

5. Oefen'ed income laXeSarisewhen items are inelUOOdin taxable income in different periods than they are included in rates therefore, ift/1e item giving rise 10the ADIT is not 

included in the iOf'lOOIa, the associated ADfT alTlOlA'tl s.h31! be excluded 

Issued by: Charles A White 










Original Sheet No_ 214-K 


Attachment 2 - Taxes other Than Income Taxes Worksheet 

Other Taxes 

Page 263 

Col Ii) 

AI/ocator 

Allocated 

Amount 

Plant Related Gross Plant Allocator 

Total Plant Related o 0.0000% o 

Labor Related Wages & Salary Allocator 

Total Labor Related o 0.0000% o 

Other Included Gross Plant Allocator 

Total Other Included o 0.0000% o 

Total Included 

o 

Currently 

Excluded 

Total as reported on p. 263(;) o 




Effective: March J, 2010







Original Sheet No_ 214-L 


Account 447 - Sales for Resale 

1 4470004 - Transmission Short·Term (Note 1) 

24470006 - Transmission Long-Term 

34470004 - 5T Ancillary Services Revenue (Note 1) 

44470006 -l T Ancillary Services Revenue (Note 1) 

5 Total Sales for Resale Transmission Revenues 

Attachment 3 - Revenue Credit Workpaper 

(Sum Lines 1-5) $ 

Total 

Account 


Revenue Credit 

$ 

Amount 

Account 454 - Rent from Electric Property 

6 Rent paid by affiliates to SCE&G for use of General Plant Assets (Note 2) 

7 Land Rental Revenue - Generation Property 

8 Pole Attachment Rental Revenue - Cable & Telephone (Note 2) 

9 Well Rental Revenue - Generation Property 

10 Revenue from Special Facilities (Note 3) 

11 Revenue from Directly Assigned Transmission Facilities (Note 3) 

12 Revenue from Directly Assigned Distribution Facilities (Note 3) 

13 Imbalance Penalties 

14 Miscellaneous Charges & Adjustments (Note 2) 

15 Total Rent Revenues 

(Sum Lines 7-9) $ 

$ 

Account 456.1 - Other Electric Revenues 

16 Transmission of Electricity for Others - Form 1, pg 330 less Network Customers & Woodland Hills (Note 1) 

17 Ancillary 1 & 2 Charges - Form 1, pg. 328, column mn less Network Customers (Note 1) 

18 Transmission of Electricity for Others - Network Customers 

19 Ancillary 1 & 2 Charges - Network Customers (Note 1) 

20 Woodland Hills Contract (Note 1) 

21 Total Other Electric Revenues (Sum Lines 11-13) $ 

$ 

22 Totals 

(Line 5 + 15 + 21) 

",$b~~';"'_ 

$ 

Notes: 

23 Note 1: All revenues related to transmission that are received as a transmission owner, for 

which the cost of the service is recovered under this formula, except as specifically provideC 

for elsewhere in this Attachment or elsewhere in the formula will be included as a revenue 

credit or induded in the peak on line 170 of Appendix A. Types of revenue included as a 

revenue credit are: short-term point to point sales; ancillary rate 1 revenue and other 

revenue not included in the peak. 

24 Note 2: Ratemaking treatment for the following specified secondary uses of transmission 

assets: (1) right-of-way leases and leases for space on transmission facilities for 

telecommunications; (2) transmission tower licenses for wireless antennas; (3) right-at-way 

property leases for farming, grazing or nurseries; (4) licenses at intellectual property 

(including a portable oil degasification process and scheduling software); and (5) 

transmission maintenance and consulting services (including energized circuit maintenance 

high-voltage substation maintenance, safety training, transformer oil testing, and circuit 

breaker testing) to other utilities and large customers (collectively, products). This revenue 

is allocated to transmission based on salaries and wages and included as a revenue credit 

to the revenue 

requirement. 

25 Note 3: If the costs associated with the Directly Assigned Facility Charges are included in 

the Rates, the associated revenues are included in the Rates. If the costs associated with 

the Directly Assigned facility Charges are not included in the Rates, the associated 

revenues are not included in the Rates. 

Issued by Charles A. White 










Original Sheet No 214-M 


Attachment 4 - 100 Basis Point Increase in ROE 

Net Plant New Investment Incenitive@ 100 Basis Points 

A 

Return and Taxes with New Investment ROE Incentive 

New Investment ROE Incentive and Income Taxes o 

B Net Plant New Investment Incenitive@ 100 Basis Points 1.00% 

Return Calculation 

14' Rate Base (Une 62 • 142) 0 

Long Tenn Interest 

99 Long Tenn Interest p117.62c through SSe 0 

101 Long Term Interest (Line 99 - 100) 0 

102 Preferred Dividends enter positive p118.29c 0 

Common Stock 

103 Proprietary Capital p112.16c 0 

104 Less Preferred Stock (Acct. 204) enter negative (Line 113) 0 

106 Less Account 216.1 enter neaative ~112.12C 0 

107 Common Stock (Sum Lines 103 to 106) 0 

Capitalization 

108 Long Term Debt p112.18c through 23c 0 

109 Less Reacquired Debt enter negative p112.19c 0 

110 Less Non-interest bearing debt enter negative Attachment 8 0 

112 Total Long Term Debt (Sum Lines lOB to 111) 0 

113 Preferred Stock p112.3c 0 

114 Common Stock Line 107 0 

115 Total Capitalization (Sum Lines 112 to 114) 0 

116 Debt % Total Long Term Debt {Line 112/115) 0% 

117 Preferred % Preferred Stock (Line 113/115) 0% 

118 Common % Common Stock (Line 114/115) 0% 

119 Debt Cost Total Long Term Debt (Line 101/112) 0.0000 

120 Preferred Cost Preferred Stock (Line 102/113) 0.0000 

121 Common Cost (Note I) Common Stock Fixed plus 100 Basis Pts 0.1230 

122 Weighted Cost of Debt Total Long Term Debt (VvCLTD) (Line116*119) 0.0000 

123 Weighted Cost of Preferred Preferred Stock (Line 117* 120) 0.0000 

124 Weighted Cost of Common Common Stock (Line 118 .1211 0.0000 

12' Rate of Return ( R ) (Sum Lines 122 to 124) 0.0000 

126 Investment Return = Rate Base * Rate of Return Line 62·125 0 

Composite Income Taxes (Note H) 

127 

128 

129 

130 

131 

Income 

Tax Rates 

FIT=Federallncome Tax Rate 

SIT=State Income Tax Rate or Composite 

p = percent of federal income tax deductible for state purposes 

T T=l - {[{1 - SIT) * (1 - FIT)) I (1 - SIT· FIT * pH = 

T/{l-T) 

0.00% 

0.00% 

0.00% 

0.00% 

0.00% 

132 

133 

134 

135 

ITC Adjustment 

Amortized Investment Tax Credit 

enter negative 

p266.8f 

o 

1/(l-T) 

1/(1 - Line 128) 

100.00% 

Net Plant Allocation Factor 

(Line 1B1 

0.0000% 

ITC Adjustment Allocated to Transmission (Note L) (Line 132 * 133 * 134) o 

136 Income Tax Component = CIT={T/1-T)· Investment Return * (1-







Original Sheet No. 214-N 

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Issued by: Charles A. White Effective: March 1,2010 


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Attachment 8 - Company Exhibit - Securitization & Non-Interest Bearing Debt Workpaper 

line # 

100 

Long Term Interest 

Less l TO Interest on Securitization Bonds o 

110 

111 


Less Non-interest bearing debt 

Less Securitization Bonds 

a 

See FM1 p2S6.1, line 16 notes 

Calculation of the above Adjustments 

See Long-Term Debt Attachment 8-1 











Original Sheet No. 214- V 

APPENDIX B TO ATTACHMENT H 

FORMULA RATE IMPLEMENTATION PROTOCOLS 






SouthCarolina Electric& Gas Company 

or its designatedagent 

FERCElectric Tariff 

Fourth RevisedVolumeNo.5 

Revised OpenAccess TransmissionTariff 

Original SheetNo. 214- W 

Formula Rate Implementation Protocols 

Section 1 

General 

a) SCE&G employs a Fonnula (found at Appendix A to Attachment H of SCE&G's 

Tariff) to calculate its base transmission rates (for Network Integration Transmission 

Service and Point-to-Point Transmission Service), which rates are recalculated annually, 

by means of the Fonnula, in accordance with the Protocols set forth herein. SCE&G 

employs an Annual Update Process, which annually refreshes the transmission rates 

calculation by populating the Fonnula with current infonnation from SCE&G's FERC 

Fonn No. I. SCE&G provides on the last page of these Protocols a time-line/chart 

illustrating this Annual Update Process. The Annual Update Process does not effect 

change to the Fonnula itself. 

b) Inputs for the following components of the Fonnula are supported by SCE&G in 

its initial submission of the Fonnula: (i) rate of return on common equity; (ii) 

depreciation rates; and (iii) "Post Employment Benefits other than Pensions" pursuant to 

the Statement of Financial Accounting Standards No. 106, Employers Accounting for 

Postretirement Benefits Other than Pensions ("PBOP") charges. The values used in the 

Fonnula for each of these components shall not be changed except pursuant to a filing 

under Federal Power Act ("FPA") section 205 or 206; provided however, SCE&G may 

make a limited FP A section 205 filing pursuant to the provisions of Section 6 of these 

Protocols. Any other modifications to the Fonnula shall be made through an FPA section 

205 or section 206 filing. 

Section 2 

Annual Update Process 

a) The Annual Transmission Revenue Requirement ("ATRR") and the transmission 

rates derived under the Fonnula shall be applicable to services on and after June 1 of a 

given calendar year! through May 31 of the subsequent calendar year ("Rate Year"). 

b) On or before May 15 of each year, SCE&G shall (i) recalculate its ATRR, 

producing the "Annual Update" for the upcoming Rate Year, (ii) post such Annual 

Update on its Internet website via link to the http://www.oatioasis.com/sceg/index.html. and 

(iii) submit such Annual Update to the Federal Energy Regulatory Commission 

("FERC") as an infonnational filing. 

NotwithstandingSection 2.a, the first Rate Year shall commenceon the effective date of 

the Formulaestablishedby the FERC. 

Issued by: CharlesA. White 

Vice President- Electric Transmission 

Issuedon: December29, 2009 

Effective: March I, 20I0







Original Sheet No. 214-X 

c) If the date for making the Annual Update posting/filing should fall on a weekend 

or a holiday recognized by the FERC, then the posting/filing shall be due on the next 

business day. 

d) The date on which the last of the events listed in section 2.b. or 2.c. occurs shall be 

that year's "Publication Date." 

e) Upon written request for a particular year's Annual Update by (i) any transmission 

customer taking service under the Tariff, (ii) the Public Service Commission of South 

Carolina, or (iii) the South Carolina Office of Regulatory Staff, SCE&G will promptly 

make available to such entity, and/or a consultant designated by it, a "workable" Excel 

file containing that year's Annual Update data. 

f) The Annual Update for the Rate Year: 

(i) shall, to the extent specified in the Formula, be based upon SCE&G's FERC 

Form No. 1 data for the most recent calendar year, and, to the extent specified in the 

Formula, be based upon the books and records of SCE&G consistent with FERC 

accounting policies; 

(ii) shall, as and to the extent specified in the Formula, provide supporting 

documentation for data not otherwise available in the FERC Form No. I that are used in 

the Formula;2 

(iii) shall provide notice of material changes in SCE&G's accounting policies 

and practices from those in effect for the calendar year upon which the immediately 

preceding Annual Update was based ("Material Accounting Changes,,);3 

(iv) shall be subject to challenge and review only in accordance with the 

procedures set forth in these Protocols and only as to the appropriateness of the 

application of the Formula according to its terms and the procedures in these Protocols 

2 

Each input to the Formula will be either taken directly from the FERC Form No. I or 

reconcilable to the FERC Form No. I by the application of clearly identified and supported information. 

Where the reconciliation is provided through a worksheet included in the filed Formula template, the 

inputs to the worksheet will be either taken directly from the FERC Form No. I or reconcilable to the 

FERC Form No. I by the application of clearly identified and supported information. 

3 

Such notice may incorporate by reference applicable disclosure statements filed with the 

Securities and Exchange Commission ("SEC"). 











Original Sheet No. 214-Y 

(including terms and procedures related to challenges concerning Material Accounting 

Changes); and 

(v) shaH not seek to modifY the Formula and shaH not be subject to chaHenge 

by anyone seeking to modifY the Formula (i.e., all such modifications/amendments to the 

Formula will require, as applicable, a FPA section 205 or section 206 filing). 

h) As part of the Annual Update Process, SCE&G wiH calculate a True-Up between 

the forecasted and actual net revenue requirement and apply that True-Up as an addition 

to or subtraction from the subsequent year's net revenue requirement and resultant rates. 

This annual True-up Adjustment reconciliation amount is assumed to be incurred evenly 

over the prior Rate Year (June I through May 31). Thus, the reconciliation amount is 

divided by 12 and the monthly interest rate is applied for the appropriate number of 

months until the effective date of the revised rate (June I). The interest rate for any True- 

Up Adjustment shaH be based on the Commission's interest rate on refunds (18 C.F.R. 

§ 35.l9a). SCE&G will use the Commission's published First Quarter interest rate as 

applied to the month of March, i.e., the published First Quarter interest rate divided by 

365 and multiplied by the number of days in March (31 days). A constant monthly 

payment is then calculated that will recover the total amount of interest accrued over a 12 

month period with interest at the monthly interest rate. The sum of these 12 monthly 

payments is then added to (or subtracted from) the ATRR recovered in the Rate Year 

beginning on June I. 

Section 3 

Annual Review Procedures 

Each Annual Update shaH be subject to the following review procedures 

Review Procedures"): 

("Annual 

a) Any interested party shaH have up to 120 days after the Publication Date ("Review 

Period") (unless such period is extended with the written consent of SCE&G) to review 

the calculations and to notifY SCE&G in writing of any specific chaHenges, to the 

application of the Formula ("Preliminary Challenge"). 

b) Interested parties shall have up to 90 days after each annual Publication Date 

(unless such period is extended with the written consent of SCE&G) to serve reasonable 

information requests on SCE&G, provided, however, that the potentiaHy interested 

parties shaH make a good faith effort to submit consolidated sets of information requests 

that limit the number and overlap of questions to the maximum extent practicable. Such 











Original Sheet No. 214-Z 

infonnation requests shall be limited to what is necessary to detennine if SCE&G has 

properly applied the Fonnula and the procedures in these Protocols, and shall not 

otherwise be directed to ascertaining whether the Fonnula is just and reasonable. In 

addition, such infonnation requests shall not solicit infonnation that solely relates to 

inputs that are stated values or cost allocation methods that have been detennined by any 

final order by the FERC pursuant to FPA sections 205, 206 or 306 with respect to 

SCE&G (including an order approving a settlement), except that such infonnation 

requests shall be pennitted if they seek to detennine if there have been material changed 

circumstances and to confinn consistency with the applicable order (and associated 

settlement, if any). 

c) SCE&G shall make a good faith effort to respond to infonnation requests 

pertaining to the Annual Update within 15 business days of receipt of such requests. 

SCE&G may give reasonable priority to responding to requests that satisfY the 

practicable coordination and consolidation provision above. 

d) Preliminary or Fonnal Challenges related to Material Accounting Changes are not 

intended to serve as a means of pursuing other objections to the Fonnula. Failure to 

make a Preliminary Challenge with respect to a Material Accounting Change to an 

Annual Update shall not act as a bar with respect to making a Fonnal Challenge as to that 

Annual Update nor shall failure to make a Preliminary Challenge or Fonnal Challenge as 

to any Annual Update act as a bar to a Preliminary Challenge or Fonnal Challenge 

related to any subsequent Annual Update to the extent such Material Accounting Change 

affects the subsequent Annual Update. 

e) Preliminary or Fonnal Challenges related to Material Accounting Changes shall be 

subject to the resolution procedures and limitations in Section 4, except that Section 4.c. 

shall not apply. In any proceeding initiated to address a Preliminary or Fonnal Challenge 

or sua sponte by the Commission, a party or parties (other than SCE&G) seeking to 

modifY the Fonnula in any respect shall bear the burden of proving that the Fonnula is no 

longer just and reasonable without such modification and that the proposed modification 

is just, reasonable and consistent with the original intent of the Fonnula and the 

procedures in these Protocols; provided, however, that in any such proceeding, in 

detennining whether the Fonnula is no longer just and reasonable without modification to 

reflect a Material Accounting Change and whether the proposed modification is just and 

reasonable, no offsets unrelated to the applicable Material Accounting Changes may be 

considered. 











Original Sheet No. 2l4-AA 

Section 4 

Resolution of Challenges 

a) If SCE&G and an interested party have not resolved a Preliminary Challenge to an 

Annual Update within 21 days after the Review Period, the interested party shall have an 

additional 21 days (unless such period is extended with the written consent of SCE&G to 

continue efforts to resolve the Preliminary Challenge) to make a Formal Challenge with 

the FERC, pursuant to 18 C.F.R. § 385.206, which shall be served on SCE&G by 

electronic service on the date of such filing. However, there shall be no need to make a 

Formal Challenge or to await conclusion of the time periods in Section 3 and 4 if the 

FERC already has initiated a proceeding to consider the Annual Update. A party's 

Formal Challenge may not raise any issue that was not the subject of that party's 

Preliminary Challenge during the applicable Review Period. 

b) Any response by SCE&G to a Formal Challenge must be submitted to the FERC 

within 30 days of the date of the filing of the Formal Challenge, and shall be served on 

the filing party(ies) by electronic service on the date of such filing. 

c) Except as provided in section 3.e, in any proceeding initiated by the FERC 

concerning the Annual Update or in response to Formal Challenge, SCE&G shall bear the 

burden of proving that it has reasonably applied the terms of the Formula, and the 

applicable procedures in these Protocols, for that year's Annual Update. 

d) Except as specifically provided herein, nothing herein shall be deemed to limit in 

any way (i) the right of SCE&G to file unilaterally, pursuant to FPA section 205 and the 

regulations thereunder, to change the Formula or any of its inputs (including, but not 

limited to, rate of return on common equity and transmission incentive rate treatment) or 

to replace the Formula with a stated rate, or (ii) the right of any other party to request 

changes to the Formula pursuant to FPA section 206 and the regulations thereunder. 

e) Subject to section 3.e above, it is recognized that resolution of Formal Challenges 

concerning Material Accounting Changes may necessitate adjustments to the Formula 

input data for the applicable Annual Update or changes to the Formula to achieve a just 

and reasonable end result consistent with the intent of the Formula. 

Section 5 Changes Pursuant to Annual Update Process 

Any changes to the data inputs, including but not limited to revisions to SCE&G's FERC 

Form No. I, or as the result of any FERC proceeding to consider the Annual Update, or 











Original Sheet No. 214-BB 

as a result of the procedures set forth herein, shall be incorporated into the Formula and 

into the charges produced by the Formula (with interest determined in accordance with 

18 C.F.R. § 35.19a) in the Annual Update for the next effective Rate Year. This 

reconciliation mechanism shall apply in lieu of mid-Rate Year adjustments and any 

refunds or surcharges. However, actual refunds or surcharges (with interest determined 

in accordance with 18 C.F.R. § 35.19a) shall be made in the event that the Formula is 

replaced by a stated rate for SCE&G. 

Section 6 

Limited Filings 

SCE&G may, at its discretion and at a time of its choosing, make a limited filing pursuant 

to FPA section 205: 

i) to change its ROE, change its PBOP accruals, change its 

amortization/depreciation rates and/or add new amortization/depreciation rates. The sole 

issue in any such limited section 205 filing shall be whether such proposed changes are 

just and reasonable, and shall not include other aspects of the Formula Rate. Changes in 

depreciation rates to track a state commission order shall become effective on the same 

date as the state commission order becomes effective, but no earlier than the effective 

date of the limited section 205 filing to incorporate such changes in the Formula Rate. 

ii) to update the references in the Formula to reflect any FERC changes to the 

format and/or content of the FERC Form No.1 or the Uniform System of Accounts that 

affect the calculations set forth in the Formula, but do not affect the rates for 

Transmission Service derived from the Annual Update. The sole issue in any such 

limited section 205 filing shall be whether such proposed changes are just and reasonable, 

and shall not include other aspects of the Formula Rate. 











Original Sheet No. 214-CC 

SCE&G Rate Implementation 

Timeline 

Beginning 

of the "Rate 

Year" 

Juno! 

ReviewPeriod 

12D Days after 

Publication Date 

(To review 

calculation lind 

nalify SCE&G in 

writing) 

F annal Challenge Perioc1- 21 

ThLys after the end of the 

Prelimin&y Challenge Period 

(Intereste d parties may not 

raise l!IIlyis$ue that was not the 

subjed ofthlt party's 

Preliminary Challenge) 

r"-----' 

recalculate its 

Annuol 

T f81lSm1Ssion 

Revenle 

Requirements 

The date on which the last of 

these everts occur is the 

Publication Date: 

(1) Posting of the Annual Update 

on the Intemet Website 

(1) File Annual Update with 

FERC as an infotmational filing 

Interested parties 

shall have up to 90 

Days after 

Publication Date to 

seNe infonnation 

requests 

Prelimi:n&y 

Challenge.21 

Days after the 

end of the 

Review Period 

SCE&G Has 15BlI$ines\: Days to 

respond to infonnation requests from the 

receipt of such requests (Oct. 6 would be 

last possible day) 

No challenges 

brought up, 

Anmal Update 

becomes Final 

(Subjectto 

judicial 

review) 

SCE&Ghas 

30 Days to 

respood to II. 

Formal 

Challenge 

fi'eJll tlae 

0....... 

ill'IIAl 

Challe:nge B 

filed' 

"'Date for response bySCE&G is based an Fotm.:a1Chollenge filed on the 

last day of the F onnal Challenge P erio d 

Rate Yeftf 

May31, 

,"XX 




Effective: March 1, 20 IO



DOCKET ERIO-_-OOO 

APPENDIX B TO DECEMBER 29, 2009 FILING 

REDLINED TARIFF SHEETS




FERC Electric Tariff Superseding Qriginal Sheet NQ 9 


Revised Open Access Transmission 

Tariff 

OrigiaalFjrst Reyised Sheet No.9 

Form Of Service Agreement For Firm Point- To-Point Transmission Service 

176 

ATTACHMENT A-I 180 

Form Of Service Agreement For The Resale, Reassignment Or Transfer Of 

Point- To-Point Transmission Service 180 

ATTACHMENT B 184 

Form Of Service Agreement For Non-Firm Point-To-Point Transmission 

Service 184 

ATTACHMENT C 186 

Methodology To Assess Available Transfer Capability 186 

ATTACHMENT D 198 

Methodology for Completing a System Impact Study 198 

ATTACHMENTE 203 

Index Of Point- To-Point Transmission Service Customers 203 

ATTACHMENTF 209 

Service Agreement For Network Integration Transmission Service 209 

ATTACHMENT G 211 

Network Operating Agreement 211 

ATTACHMENT H 214 

AfHlllai TFaflSmissisfl ReveRlIe Reqllffemeflt.B.iili;:For Network Integration 

Transmission Service 214 

Appendjx A 

Appendjx B 

ATTACHMENT I 

Index Of Network Integration Transmission Service Customers 

ATTACHMENT] 

Procedures for Addressing Parallel Flows 

ATTACHMENT K 

Transmission Planning Process 

Appendix K-2 

Appendix K-3 

Southeast Inter-Regional Participation Process 

ATTACHMENT L 

Creditworthiness Procedures 

214-A 

214-Y 

215 

215 

216 

216 

217 

217 

238 

239 

239 

270 

270 



Issued on: Ma,sH 17, 2QQ8 December 29 2009 

Effective: March 17, 2QQgI 2010 

filed Ie seml'ly with O,d., of tHe Fedefill gFleFgYRegulato,y CemmissioFl, 0,,1., Ne. g9Q A, f)osl,et 

Nes. RMQ5 17 QQI, el ,Ii., issued f)esemee, 28, 2()g:y, 121 fgRC '\I ~I ,297 (2g()7).




FERC Electric Tariff Superseding Qriginal Sheet NQ 143 



OFigiaalFjrst Reyised Sheet No. 143 

Utility Practice, also may Curtail Network Integration Transmission 

Service in order to (i) limit the extent or damage of the adverse condition(s) 

or disturbance(s), (ii) prevent damage to generating or transmission 

facilities, or (iii) expedite restoration of service. The Transmission 

Provider will give the Network Customer as much advance notice as is 

practicable in the event of such Curtailment. Any Curtailment of Network 

Integration Transmission Service will be not unduly discriminatory relative 

to the Transmission Provider's use of the Transmission System on behalf of 

its Native Load Customers. The Transmission Provider shall specify the 

rate treatment and all related terms and conditions applicable in the event 

that the Network Customer fails to respond to established Load Shedding 

and Curtailment 

procedures. 

34. Rates and Charges 

The Network Customer shall pay the Transmission Provider for any Direct 

Assignment Facilities, Ancillary Services, and applicable study costs, consistent 

with Commission 

policy, along with the following: 

34.1 Monthly Demand Charge: 

The Network Customer shall pay a monthly Demand Charge, which shall 

be determined by multiplying its Laaa Ratia Share times aHe t'""elflh (1/12) 



Issued on: MeF6ft 17, 2998PecewbeT 29 2009 

Effective: March 17, 29981 2010 

Filed t9 69"'1'1)' willi OffieF 9ft"e FedeFal BneFg), Reg"lat9F), C9mmissi9n, OffieF ~19. 899 A, Deel,et 

~Ies. RM95 17 991, ef al., issued DeeemeeF 28, 2997, 121 FBRC '1161,297 (2997).




PERC Electric Tariff Supersedjpg Original Sheet NQ .w 



OrigiflalFjrst Reyised Sheet No. 144 

ef tke TfEiHsmissieR Pfevisef's ARRlIal TFaRSmissieR ReveRlIe 

ReqaireffieetMoothly Network I pad PllfSllant to Section 342 by the rate 

specified in SskesllleAttachment H. 

34.2 Determination of Network Customer's Monthly Network Load: 

The Network Customer's monthly Network Load is its hourly load 

(including its designated Network Load not physically interconnected with 

the Transmission Provider under Section 31.3) coincident with the 

Transmission Provider's Monthly Transmission System Peak. 

34.3 Determination of Transmission 

Transmission System Load: 

Provider's 

Monthly 

The Transmission Provider's monthly Transmission System load is the 

Transmission Provider's Monthly Transmission System Peak minus the 

coincident peak usage of all Firm Point- To-Point Transmission Service 

customers pursuant to Part II of this Tariff plus the Reserved 

Capacity of all 

Firm Point- To-Point Transmission 

Service customers. 

34.4 Redispatch Charge: 

The Network Customer shall pay a Load Ratio Share of any redispatch 

costs allocated between the Network Customer and the Transmission 



Issued on: Mareh 17, 2QQ8Pecember 29 2009 

Effective: March 17,2008 I 20! 0 

fil.d ts ssml'l), with Ord.r sf th. f.d.ral BAerg),Reg..latsry CemmissieA, Order ~Ie. 890 A, Deeket 

~Ies. RMQ5 17 QQI, .1til., iss... d geeemeer 28, 2QQ7,121 fERC'\I (;1,297 (2QQ7).




PERC Electric Tariff Superseding Origjnal Sheet NQ ill 



OrigiaalFjrst Reyised Sheet No. 145 

Provider pursuant to Section 33. To the extent that the Transmission 

Provider incurs an obligation to the Network Customer for redispatch costs 



Issued on: ~4aFeH 17, 2QQ8pecember 29 2009 

Effective: March 17, 2QQ8l 2QJQ 

files Ie ee"",ly wilh Oraer sf Ih. fes.ral eR.rgy R.g ..lalel)· CemmissieR, Ora.r ~Ie. 89Q A, Deekel 

Nes. RMQ5 17 QQI, el "t.,issHee Deeemeer 28, 2QQ7,121 feRC '\I ~I ,297 (2QQ7).




FERC Electric Tariff Superseding Original Sheet No.1Q6 



Tariff 

ORgisalFirst Revised Sheet No. 166 

SCHEDULE 7 

Long-Term Firm and Short-Term Firm Point-To-Point 

Transmission Service 

1) Yearly. Monthly. Weekly. and Daily Delivery: The rates for Yearly Delivery. 

Monthly Delivery. Weekly Delivery. Daily Delivery for On-Peak Days. and Daily 

Delivery for Off-Peak Days are derived from the Fonnula. which is set forth in 

Appendix A to Attachment H of this Tariff ("Appendix A"). 

The rates will be 

updated annually and posted on SCE&G's OASIS in accordance with the Fonnula 

Rate Implementation Protocols set forth in Appendix B to Attachment H of this 

Tariff. 

The Transmission Customer shall compensate the Transmission Provider each 

month for Reserved Capacity at the sum of the applicable charges set forth below: 

1) YeoFIy lIelh'eFY: ORe twelftll of tile lIemoRIi ellaFge of $B.gIl/K'lv'lll 

Yearly Delivery Charge: 

the Rate for Yearly Delivery (ie .. the 

amonnt shown on Appendix A> times the numher of Megawatts 

("MWs") of Reserved Capacity peFfor the year~ divided by J 2. 

2) MORtllly delivery: $UIlIKWb) Monthly Delivery Charge: the Rate 

for Monthly Delivery (ie .. 1Ilth of the amount shown on Appendix A) 

times the number of MWs of Reserved Capacity peFfor the month. 

Issued by: Charles A. White Effective: March \7, 2QQ8I. 2010 


Issued on: MaFeh 17, 2QQ8 December 29.2009 

fi!ea te eefR~!Y with OFaeF ef the fedeFa! Io:seFgYRegu!atel)' Cefflffiissies, OFaeF ~Ie. 89Q A, Deeket 

Nes. RMQ§ 17 QQI, elel., issued DeeefReeF2S. 2QQ7, 121 fIo:RC '1161,297 (2QQ7).




FERC Electric Tariff Superseding Original Sheet No. 167 



OFigiaalFirst Revised Sheet No. 167 

J) WeelEly deliveFY: SO.JOIKWc) Weekly Delivery Charge: the Rate for 

Weekly Delivery (ie.. 1I52 nd of the amount shown on Appendix Al 

times the number of MWs of Reserved Capacity jlCFfor the week. 

~) Daily deliveFyDelivery Charge: 

On-Peak: SO.OSIKWof ReseFved Capaeity peF day. 

Off Peal




FERC Electric Tariff Superseding Original Sheet No. l6..8 




~~ Definition of Qn-Peak and Qff-Peak Days: For Daily Delivery: On-Peak Days 

are Monday through Friday, and all other days are Off-Peak Days. 


service as follows~ (I) any offer of a discount made by the Transmission Provider 

must be announced to all Eligible Customers solely by posting on the OASIS,~(2) 


Issued by: Charles A. White Effective: March 17, 2ggg 1 2010 


Issued on: Ma.eR 17, 2ggg December 29 2009 

filee te "eFflplywith O.ee. efthe feee.al liaeFgy Regulate,",' CeFflFflissieF!,O"ler Me. 89g A, De6kel 

Mes. RMgj 17 ggl, ef 8/., issuee DeeeFflee. 28, 2gg7, 121 fliRC, 61,297 (2g07).




or its designated agent Original Sheet No. 167-A 

FERC Electric Tad ff 



OASIS,~ and (3) once a discount is negotiated, details must be immediately posted 

on the OASIS. 

For any discount agreed upon for service on a path, from point(s) 


discounted transmission service rate for the same time period to all Eligible 

Customers on all unconstrained transmission paths that go to the same point( s) of 

delivery on the Transmission 

System. 

~ Resales: The rates and rules governing charges and discounts stated above shall 



Issued by: Charles A White Effective: March I 20 I0 


Issued on' December 29 2009




FERC Electric Tariff Superseding Original Sheet No 168 



Tariff 

GFiginalFirst Revised Sheet No. 168 

SCHEDULES 

Non-Firm Point- To-Point Transmission Service 

1) Monthly. Weekly. Daily. and Hourly Delivery: The rates for Monthly Delivery. 

Weekly Delivery. Daily Delivery for On-Peak Days. Daily Delivery for Off-Peak 

Days. Hourly Delivery for On-Peak Hours. and Hourly Delivery for Off-Peak 

Hours are derived from the Formula. which is set forth in Appendix A to 

Attachment H of this Tariff ("Appendix A''). The rates will be updated annually 

and posted on SCE&G's OASIS in accordance with the Formula Rate 

Implementation Protocols set forth in Appendix B to Attachment H of this Tariff. 

The Transmission Customer shall compensate the Transmission Provider for Non- 

Firm Point- To-Point Transmission Service up to the sum ofthe applicable charges 

set forth below: 

1) M!lRtllly lielivery: $U()fKWa) Monthly Delivery Charge: The 

Rate for Monthly Delivery (Le,. I1l2th of the amount shown on 

Appendix A) times the number of Megawatts ("MWs") of Reserved 

Capacity pet'for the month. 

$().()§/KW !If Resernli Callaeity lIer liay. 

$().()4286/KW of ReseR'eli Callaeity lieF liay. 

Issued by: Charles A. White Effective: March 17, 2QQSI 2010 


Issued on: Marel! 17, 2QQ8 December 29 2009 

file a Ie eeHlflly will! Graer eflhe feaeral ellergy RegHlale!?' CeFllFllissiell, G.aer ~Ie. 89Q A, Deekel 

Nes. RMQ§ 17 QQ1, el al., issHea DeeeFllee. 28, 2QQ7, 121 FeRC, 61,297 (2QQ7).




FERC Electric Tariff Suoerseding Original Sheet No. ill 



O.igil\alFirst Revised Sheet No. 169 

(Oa Peak hSliFS se,;iH at 7 a.m. Eastern Pre\ailiBg Time ami eBB at II p.m. 

::=~i~rg;~~i~!;=~::i5Z"tt~::l~~Tt~I::=aB:~:rCh~s=~ 

DBJ'. All other houl'J are Off Peal, hSlifS.) 

c) Daily Delivery Charge: 

On-Peak: The Rate for On-Peak Daily Delivery (ie .. l/sth of the 


number ofMWs of Reserved Capacity for the daY. 

Off-Peak: The Rate for Off-Peak Daily Delivery (ie .. lmh of the 

Rate for Weekly Delivery (shown in subsection (b) abovel) times the 


The total semaas charge in any week, pursuant to a reservation for Daily 

seliyeryDelivery. shall not exceed the rateRate for Weekly Delivery. 

specified in seetisasubsection 

(~~) above, times the highest amount III 

kilsvra!tsMWs of Reserved Capacity in any day during such week. 

Hourly selh'e~DelivfY cbaf~e: The b!lsic charge sha\l be that agreed 

upon oy the Pa les at ne hme IS service IS reservea and III no event shall 

~ii. 

exceed~ 

OR Peal, 

i~i#w·et%:1 

$J.B/·MWH; oRd 

3i(i~erJo -cliriftr'rift 

I n Jl% 1 i rv ed 

Off-Peak: the Rate for Off-Peak Hourly Delivery (i.e.. 1!24th of the 

Rate for Off-Peak Daily Delivery (shown in subsection (el abovel) 

times the number of MWs of Reserved Capacity for the hour. 



Issued on: Mareh 17. 2()()80ecember 29 2009 

Effective: March 17, 2()()81 2010 

filed te ee"",l), '




FERC Electric Tariff Superseding Original Sheet No l1Q 




The total eemaRe charge in any day, pursuant to a reservation for Hourly 

eelivefyDeliverv, shall not exceed the rateRate for On-Peak Daily Delivery. 

specified in seetieHsubsection (JI




or its designated agent Original Sheet No. 170-A 




discounted transmission service rate for the same time period to all Eligible 


delivery on the Transmission 

System. 

~ Resales: The rates and rules governing charges and discounts stated above shall 



Issued by: Charles A. White Effective: March I 2010 

Vice President Electric Transmission 

Issued on: December 29 2009




or its designated agent OFigiRal First Reyised Sheet No. 214 

FERC Electric Tariff Superseding Qriginal Sheet No 214 


ATTACHMENT 

H 

ltRRtlal TF8RsmissioR ReveRue ReElHiFemeRt 

RlW:..For Network Integration Transmission Service 

The ARfHlaiTraRsmissieR ReveRlie ReEtlliremeRt fur flllflleses ef thel. The rate for 

Network Integration Transmission Service shall be $43,427,200.the rate 

(expressed in $/MW -yearl set forth in Appendjx A hereto divided by 12 The rate 

for Network Integration Transmjssjon Service wi]] be updated annual1y and posted 

00 SCE&G's OASIS in accgrdance with the FowJI];] Rate ImpJementatioQ 

protoCQls set forth in Appendjx B hereto 

2.. The ameliRt iR (1)FormuJa jn Appendjx A hereto and resultant Network 

Integratiop Transmissjqn Servjce rate. shall be effective until amended by the 

Transmission Provider or modified by the Commission. 

3.. All quantities used in calculating the Network Customer's Network Load and 

Transmission Provider's Monthly Transmission System Peak shall be adjusted to 

the Transmission System input level, i.e., shall include the transmission capacity 

amount associated with any applicable losses. As a result the Customer's load as 

metered at the pointes) of Delivery (trapsmissiop exit level) wi]] he ipcreased 

usip2 the Real power Loss factor shown ip SectjQP 28 5 oftbis Iariffto hrjpi tbe 

Customer's load to the 2eperatiop level. 

Issued by: 


Issued on: Mareh 17, 2()()8 December 29 2009 

Charles A. White Effective: March 17, 2()()8.u




EXHIBIT NO. SCE-l 

DIRECT TESTIMONY 

OF 

JIMMY ADDISON 

ON BEHALF OF SOUTH CAROLINA ELECTRIC & GAS COMPANY


Exhibit No. SCE-I 


BEFORE THE 


South Carolina Electric & Gas Company Docket No. ERlO- -000 

DIRECT TESTIMONY AND SUPPORTING EXHIBITS OF 

JIMMY ADDISON 



Direct Testimony of Jimmy Addison 

Docket ERIO· -000 

Page I ofI9 

Exhibit No. SCE- I 

1 I. 

INTRODUCTION 

AND OUALIFICATIONS 

2 Q. 

PLEASE STATE YOUR NAME, TITLE AND BUSINESS ADDRESS. 

3 A. 

4 

My name is Jimmy E. Addison. I am Senior Vice President and Chief Financial Officer 

of South Carolina Electric & Gas Company ("SCE&G" or the "Company"), on whose 

5 

behalf I am testifying in this proceeding. 

I am also Senior Vice President and Chief 

6 

7 

Financial Officer of SCANA Corporation ("SCANA"), which is the parent company of 

SCE&G. My business address is 100 SCANA Parkway, Cayce, South Carolina 29033. 

8 Q. 

9 

BRIEFLY OUTLINE YOUR RESPONSIBILITIES AS SENIOR VICE 

PRESIDENT AND CHIEF FINANCIAL OFFICER. 

10 A. 

11 

12 

13 

14 

15 

I provide leadership, direction and technical expertise related to treasury and finance 

processes and functions. I am responsible for monitoring the Company's present and 

prospective financial condition; for formulating strategies to ensure that the Company can 

meet its capital requirements at the lowest reasonable cost; and for managing all 

accounting and financial matters related to the Company. I am responsible for 

recommending and implementing the financing required to achieve targeted capital 

16 

structure objectives. 

In that regard, I meet regularly with members of the financial 

17 

community, including Wall Street analysts and credit rating agency personnel who follow 

18 

the electric utility industry in general and SCANAlSCE&G specifically. 

In these 

19 

20 

21 

meetings we discuss their perceptions and concerns about the Company, its financial and 

business position, its long term strategy, capital plans, the capital markets and the utility 

industry generally. We also discuss the various risk factors that the Company faces as



Docket ERl 0·_·000 

Page 2 of19 

Exhibit No. SeE·l 

seen by investors. I am also regularly involved in discussions of investors' perspectives 

2 

3 

4 

5 

on the Company with underwriters and other experts as such views pertain to the issuance 

or refinancing of debt and the issuance of new common stock. In addition, I provide 

financial expertise on issues related to creditworthiness, capital allocation, and financial 

testimony on behalf of SCANA Corporation's subsidiaries. 

6 Q. 

PLEASE DESCRIBE YOUR EDUCATIONAL AND BUSINESS BACKGROUND. 

7 A. 

8 

9 

10 

II 

12 

13 

I am a graduate of the University of South Carolina with a Bachelor of Science degree in 

Business Administration, majoring in accounting, and a Master of Accountancy degree; I 

am a Certified Public Accountant in South Carolina. Prior to my employment by the 

Company in 1991, I was employed for seven years by the public accounting firm of 

Deloitte & Touche, where I was designated an Audit Manager as a public utility 

accounting and audit specialist. I was also a partner in the public accounting firm of 

Hughes, Boan and Addison immediately prior to joining the Company in 1991. 

14 Q. 

15 

HAVE YOU PROVIDED TESTIMONY PREVIOUSLY IN REGULATORY 

PROCEEDINGS? 

16 A. 

17 

Yes, I have testified before the Public Service Commission of South Carolina ("SCPSC") 

and the North Carolina Utilities Commission. 

18 II. 

TESTIMONY PURPOSE AND SUMMARY 

19 Q. 

WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?



Docket ER \ 0- -000 

Page 3 ofl9 

Exhibit No. SCE-\ 

A. The purpose of my testimony is three-fold: (I) I support SCE&G's request in this 

2 proceeding to institute a formulaic determination of the annual transmission revenue 

3 requirement for transmission services provided under its Open Access Transmission 

4 Tariff (nOA TTn) and to convert network transmission service charges from the load ratio 

5 methodology to stated rates as determined annually by that formula; (2) I explain the 

6 business and financial risks peculiar to SCE&G that bear upon its credit rating and its 

7 cost of capital; and (3) I describe SCE&G's credit metrics, capital structure and support 

8 the cost of capital to be used in SCE&G's filing. 

9 Q. PLEASE SUMMARIZE YOUR TESTIMONY. 

10 A. SCE&G's currently authorized annual transmission revenue requirement and point-to- 

II point stated rates are based on the transmission investment and the costs it experienced 14 

12 years ago. Since that time, SCE&G's net transmission plant investment has more than 

13 doubled. In addition, SCE~G has begun a major transmission expansion program to 

14 accommodate two proposed nuclear units recently approved by the SCPSc. SCE&G's 

IS construction plan represents a significant increase in the Company's capital expenditures 

16 for the next decade. This fact alone substantially increases the Company's business risk. 

17 In order to meet its expected customer growth, SCE&G will almost double its investment 

18 in electric plant over the next ten years; therefore, SCE&G must access the capital 

19 markets at a time when those markets are particularly volatile. Its substantial building 

20 plan was a key factor in SCE&G's credit ratings being downgraded by all three credit 

21 rating agencies. The Company has concluded that it must institute a formula rate with 

22 projected transmission plant additions because such a formulaic methodology will



Docket ER 10- -000 

Page 4 of 19 

Exhibit No. SeE-I 

provide for recovery of its transmission costs on a more current basis, thereby improving 

2 

3 

4 

its cash flow and helping it to earn its allowed return on equity ("ROE"). This formulaic 

methodology and additional support for the associated stated rates are discussed in detail 

in the testimony of SCE&G witness Alan C. Heina, Exhibit SCE-8. 

5 III. USE OF A FORMULA RATE 

6 Q. 

7 

HOW DOES SCE&G CURRENTLY CHARGE FOR TRANSMISSION 

SERVICES? 

8 A. 

9 

10 

II 

12 

13 

14 

15 

SCE&G currently charges network transmission customers based on their load ratio share 

of an annual transmission revenue requirement established by a settlement of a Federal 

Energy Regulatory Commission ("Commission" or "FERC") rate case in Docket No. 

ER96-1 085-000 that was based on 1994 cost data. Point-to-point transmission customers 

are charged stated rates based on that same transmission revenue requirement. 

Consequently, none of the capital expenditures for transmission plant that SCE&G has 

made since January I, 1995 are included in the cost of service that forms the basis for 

current rates. 

16 Q. 

17 

18 

19 

WHY IS SCE&G SEEKING TO IMPLEMENT A FORMULAIC ANNUAL 

TRANSMISSION REVENUE REQUIREMENT AND ASSOCIATED STATED 

RATES FOR POINT -TO-POINT AND NETWORK TRANSMISSION 

SERVICES? 

20 A. 

21 

First and foremost, the formula rate, which includes a true-up mechanism, tracks 

increases and decreases in costs so that no under-recovery and no over-recovery of actual




Page 5 of 19 


costs can occur. As such, a fonnula rate not only keeps SCE&G whole in its cost 

2 recovery, but it also protects transmission customers from paying excessive rates over 

3 time by reflecting any cost changes that reduce the cost of service and, consequently, the 

4 resulting rates for transmission customers. 

5 Second, a fonnula rate mechanism significantly reduces recovery lag. Currently, 

6 SCE&G cannot recover the costs related to substantial incremental transmission 

7 investments until after it has filed a rate case with the FERC and the FERC has allowed 

8 such new rates to be effective. With a fonnula rate, SCE&G is allowed to recover its 

9 transmission costs on a more current basis, which should improve the tenns on which 

10 SCE&G can finance its new transmission investments. 

11 Third, using a fonnula rate with projected transmission plant additions improves 

12 SCE&G's cash flow, which is negatively affected by the existing recovery lag. This is 

13 important for both debt and equity investors. Investors need to be assured that SCE&G 

14 has an adequate cash flow to cover its interest payments. If SCE&G is reimbursed for its 

15 transmission expenditures on a more current basis, SCE&G's cash flow will improve. 

16 This is extremely important when a utility is financing a significant construction 

17 program. 

18 Fourth, a fonnula rate with projected plant additions will help SCE&G to earn its allowed 

19 rate of return. Standard & Poor's ("S&P") has stated (in a 2005 S&P publication titled 

20 How Returns on Equity Factor into Us. Utilities' Creditworthiness, which is attached as 

21 Exhibit SCE-2) that forward-looking cost recovery mechanisms "reduce regulatory lag by 

22 providing for recovery of estimated expenses that may be incurred in the near tenn.



DocketER! 0·_-000 

Page 6 of19 

Exhibit No. SeE-! 

Using an historical test period without updates makes it more difficult to earn the 

2 

3 

4 

authorized ROE because expenses may have already increased during the rate case 

(which can take months to complete), resulting in cost recovery that is too low even after 

new rates are set." 

5 

6 

Fifth, a formula rate supports SCE&G's credit quality which will positively affect 

SCE&G's cash flow and financial integrity. 

7 Q. 

WHAT IS SCE&G'S TRANSMISSION PLANT INVESTMENT? 

8 A. 

9 

10 

11 

12 

13 

As of December 31, 2008, SCE&G's gross transmission plant investment was 

approximately $746 million, or more than twice the gross transmission plant investment 

of $338 million included in the current stated rates calculation. Although SCE&G added 

almost $408 million of additions to its transmission system from 1995 until the end of 

2008, this investment is not reflected in the stated rates being charged its transmission 

customers. 

14 Q. 

15 

WHAT ARE SCE&G'S CAPITAL IMPROVEMENT PLANS FOR THE NEXT 10 

YEARS? 

16 A. 

17 

18 

19 

20 

SCE&G projects that it will invest approximately $349 million in new transmission 

facilities during the years 2010 through 2014. From 2015 through 2019, those 

expenditures in new transmission facilities are estimated to total $653 million. By 2019, 

SCE&G's gross transmission plant investment will be approximately $1.8 billion, which 

is more than double what it is today.



Docket ERl 0- -000 

Page 7 ofl9 

Exhibit No. SeE-l 

IV. 

CREDIT RATINGS 

2 Q. 

3 

WOULD A FORMULA RATE WITH TRANSMISSION PLANT ADDITIONS 

HELP MAINTAIN SCE&G'S CREDIT RATINGS? 

4 A. 

5 

6 

7 

8 

9 

10 

II 

12 

13 

Yes. While I cannot predict what the rating agencies will do in the future, the cost 

recovery method that we are proposing in this proceeding, i.e., the use of a formula rate 

with projected transmission plant additions, provides greater consistency, predictability, 

efficiency and timeliness with regard to cost recovery. Most ratings analysts would agree 

that the attributes of consistency and predictability, as well as efficiency and timeliness, 

of cost recovery are important gauges of how investor interests are considered in the 

overall regulatory construct. A regulatory framework that provides greater consistency, 

predictability, efficiency and timeliness of cost recovery allows an investor to more 

accurately predict how investments by utilities will be recovered and is, by nature, less 

risky than one where cost recovery is inconsistent and unpredictable. 

14 Q. 

WHAT IS THE SIGNIFICANCE OF A COMPANY'S CREDIT RATING? 

IS A. 

16 

17 

18 

19 

20 

21 

Credit ratings affect the availability and cost of both long-term and short-term capital. 

Credit ratings have a direct impact on the cost of capital through the pricing mechanisms 

that are used to determine the cost of debt in capital markets. Banks and fixed income 

investors rely on credit ratings published by the rating agencies to determine the return 

that they require on the capital they are willing to invest. Consequently, a utility's credit 

rating directly impacts the availability and cost of capital, which, in turn, affects the rates 

that customers pay when the rates are determined in proceedings before the Commission.



Docket ER 10-_-000 

Page 8 of 19 


When a company 

issues bonds, the price is derived by adding a credit spread to the 

2 

3 

4 

5 

6 

7 

8 

9 

10 

II 

benchmark U.S. Treasury Bond with a maturity similar to the new bond the company is 

issuing. The credit spread added to the benchmark Treasury Bond is based on perceived 

credit risk. In times of high liquidity and low perceived credit risk, spreads narrow. In 

times of low liquidity and higher perceived credit risk, spreads widen. This widening of 

spreads is often referred to as the "flight to quality" as investors require higher returns 

from securities with lower credit ratings while the required return from securities with 

higher credit ratings may not change appreciably. Importantly, companies with lower 

credit ratings will generally face higher borrowing costs and will more likely have to 

enter the capital markets during times when the spreads are high. This happens because 

short-term investors tend to be less likely to lend at favorable prices or terms to 

12 

companies 

with lower credit ratings during times of tighter credit conditions. 

13 Q. 

14 

PLEASE DESCRIBE THE CREDIT RATING AGENCIES' RATINGS AND 

CATEGORIES. 

15 A. 

Credit ratings are reflections of relative risk and indicators of the likelihood that lenders 

16 

will be paid their interest and principal 

on a timely basis, and in the event of a default, to 

17 

18 

19 

20 

21 

22 

recover some or all of their investment. A company with an AA rating is viewed by 

investors as having less risk than a company with an A rating. S&P, Moody's Investors 

Service ("Moody's") and Fitch Ratings ("Fitch"), the three primary credit rating agencies. 

provide ratings for business entities as a whole and for the various debt issuances of each 

entity. Each of the primary credit rating agencies issues a corporate credit rating ("CCR") 

which reflects the general creditworthiness of the business enterprise. The CCR



Docket ERIO- -000 

Page 9 of 19 

Exhibit No. seE-I 

represents an opinion about an issuer's overall capacity to pay its financial obligations 

2 

3 

4 

5 

6 

when scheduled. It is not a rating of individual securities or specific subsidiaries, but 

instead the core rating of the entire business enterprise from which ratings of individual 

securities are derived. Issuer ratings reflect the likelihood that principal and interest on 

specific debt issues will be paid in a timely manner and take into account the recovery 

prospects in an event of default. 

7 

8 

9 

10 

II 

12 

13 

The investment grade categories include the High Grade (Triple-A and Double-A ratings) 

and the Medium Grade category (Single-A and Triple-B ratings). S&P, Moody's and 

Fitch further delineate CCR categories by the use of +'s and -'s (S&P and Fitch) or 1,2,3 

(Moody's) to show a company's relative standing within the categories. The highest 

investment grade rating is AAA and the lowest is BBB-. Ratings of BB+ through D 

(Default) are considered Non-Investment grade (commonly referred to as "Junk" status) 

ratings. 

14 Q. 

WHAT ARE SCANA'S AND SCE&G'S 

CREDIT RATINGS? 

15 A. 

16 

17 

18 

S&P, Moody's and Fitch recently completed in-depth reviews of SCANA and SCE&G as 

part of a comprehensive review of the companies' credit ratings. All three credit rating 

agencies downgraded SCANA and SCE&G one notch. The downgrades were driven by 

the financial pressure and increased business risk from SCE&G's plans to construct and 

19 

finance two nuclear generating units for service in 2016 and 2019, respectively. 

In 

20 

21 

22 

addition to its downgrade, Moody's changed its rating outlook for both companies to 

"negative" primarily due to "concerns related to the new nuclear program .... " Exhibit 

SCE-3(B). Exhibit SCE-3 contains S&P's (Exhibit SCE-3(A», Moody's (Exhibit SCE-




Page lOofl9 


3(B)) and Fitch's (Exhibit SCE-3(C)) downgrades. Exhibit SCE-4 is a complete list of 

2 SCE&G's and SCANA's credit ratings as of July, 2009. See also Exhibit SCE-5 for 

3 copies ofSCE&G's most recent ratings reports by S&P (Exhibit SCE-5(A)), Moody's 

4 (Exhibit SCE-5(B)) and Fitch (Exhibit SCE-5(C)). 

5 Q. WHAT CONSIDERATIONS GO INTO ASSIGNING A CREDIT RATING? 

6 A. The primary drivers of credit ratings are business risk and financial risk. Business risk 

7 addresses the potential sources of variability in a utility's cash flow from its operating 

8 conditions as a result of various business factors such as cost structure, economic strength 

9 and diversity of service territory, competitive position, quality and depth of management 

10 team, risk management practices, supply mix and regulatory cost recovery mechanisms. 

11 The higher the business risk, the more robust the financial metrics and the lower the 

12 financial risk must be to achieve the same bond rating. 

13 v. SCE&G'S BUSINESS RISK 

14 Q. DOES SCE&G FACE SPECIFIC BUSINESS RISKS AFFECTING ITS CREDIT 

15 RATINGS? 

16 A. SCE&G's construction projects planned for completion over the next decade create 

17 substantial business risks that place great pressure on SCE&G's cost of capital. By far 

18 the most significant construction projects are SCE&G's two proposed nuclear units. 

19 SCE&G plans to construct, in partnership with South Carolina Public Service Authority, 

20 two nuclear reactors totaling 2,234 MW, of which SCE&G will own 55%. In February 

21 2009 the SCPSC approved SCE&G's combined application pursuant to South Carolina's




Page 11 of19 

Exhibit No. SCE-J 

Base Load Review Act ("BLRA") for a certificate of environmental compatibility and 

2 public convenience and necessity and for a base load review order for the two nuclear 

3 units. Under the BLRA, the SCPSC conducted a review of the need for and prudency of 

4 the proposed units, as well as the engineering, procurement and construction contract 

5 under which the units will be built. 

6 In March 2008, SCE&G and the South Carolina Public Service Authority filed an 

7 application with the Nuclear Regulatory Commission ("NRC") for a combined 

8 construction and operating license ("COL"). The COL application was reviewed for 

9 completeness by the NRC and docketed on July 31, 2008. In September 2008 the NRC 

10 issued a 30-month review schedule from the docketing date to the issuance of the safety 

II evaluation report which would signify satisfactory completion of the NRC's review. Both 

12 the environmental and safety reviews by the NRC are in progress and a COL should be 

13 issued in mid- to late-20 II. This date would support both the project schedule and the 

14 substantial completion dates for the two new units in 2016 and 2019, respectively. 

15 SCE&G has begun development of the transmission facilities that are needed to move the 

16 nuclear generation to market in a fashion that ensures continued reliable operation of 

17 SCE&G's transmission system and all interconnected transmission systems. The planned 

18 transmission facilities are estimated to cost $582 million (in escalated dollars). That 

19 compares with total gross transmission plant investment today of $746 million. The 

20 combined cost of the two planned nuclear units and associated transmission is 

21 approximately $6.3 billion (in escalated dollars) which is 37% more than SCE&G's 

22 current total company depreciated rate base of$4.6 billion (as of September 30, 2009).




Page 12 of 19 

Exhibit No. SeE-1 

The projected annual capital expenditure related to these projects will be more than 

2 

3 

4 

5 

6 

7 

8 

9 

double SCE&G's normal annual capital expenditure. According to S&P's April 2009 

ratings report for SCANA, SCE&G's proposed construction project "introduces 

significant construction and financing risk which places considerable pressure on the 

consolidated credit profile of SCAN A and necessitates that all remaining aspects of the 

business perform satisfactorily in order to provide support and preserve the current 

ratings." See Exhibit SCE-5. Moody's July 14, 2009 downgrade also reflected the 

concern that analysts have "with the material execution risks associated with a project of 

this magnitude for a company of this size." See Exhibit SCE-3. 

10 Q. 

ARE THERE ANY OTHER BUSINESS RISKS? 

II A. 

12 

Yes, those business risks involve the Commission's new transmission grid reliability 

rules. 

13 

14 

Q. HOW DO THE NEW RELIABILITY RULES IMPACT SCE&G'S BUSINESS 

RISK? 

IS 

16 

17 

18 

19 

20 

21 

A. Pursuant to the Energy Policy Act of 2005, the Commission has adopted transmission 

grid maintenance and operation reliability standards, which are enforced, under the 

Commission's auspices, by NERC. These reliability standards increase SCE&G's 

business risk in several ways. First, the new reliability regime requires performance of 

transmission operation and maintenance in accordance with a mandated set of standards 

and subject to penalties. This reliability regime is relatively new and untested; therefore, 

there is a measure of uncertainty as to both the requisites for meeting the standards and



Docket ERI 0·_-000 

Page 13 of 19 

the risk of penalty exposure. 


In addition, the new reliability metrics offer a predicate for 

2 

possible liability exposure. All this creates busines~ risk for SCE&G. 

3 

4 

5 

6 

7 

Second, new reliability standards being developed will, if approved, require duplication 

of transmission facilities to provide redundancy so that service to firm customers is not 

lost due to unplanned outages. The level of redundancy required in the future is far 

greater than the standard is today and likely will mean enormous additional transmission 

costs. 

8 

9 

10 

II 

Third, siting transmission facilities is increasingly difficult and expensive. SCE&G faces 

upward pressure on total transmission costs at a time when it will undergo the greatest 

expansion of its transmission system. All of these issues increase SCE&G's business 

risks. 

12 Q. 

WHAT ARE THE IMPLICATIONS 

FOR SCE&G OF THE FOREGOING 

13 

BUSINESS RISKS ON SCE&G'S 

RETURN ON EQUITY? 

14 A. 

15 

16 

17 

18 

19 

20 

21 

Based on my experience in raising capital for SCE&G over the years, the business risks 

facing SCE&G that I have described are well understood by the financial markets, and 

playa major role in SCE&G's ability to raise capital. In simplest terms, the riskier the 

proposition is perceived to be, the higher the cost of capital. SCE&G will not be able to 

fund the required capital investment solely from internally generated funds, and for this 

reason, SCE&G must access the capital markets for additional debt and equity to finance 

the investment in new transmission assets. In times when large-dollar projects are 

undertaken and the associated business and financial risks increase, investors look for




Page 140fl9 


higher returns to compensate them for the risks they are assuming. In a rate-regulated 

2 service, such as transmission, lenders recognize that future cash flows depend heavily on 

3 the overall allowed return on investment. The future stream of revenues that will be 

4 available to cover the contracted debt payment will vary with the authorized return on 

5 equity approved by the regulator. A higher return on equity provides greater cash flows 

6 to satisfy debt obligations in a timely manner. A higher return on equity also improves 

7 the expected earnings coverage, thereby reducing the perceived risk of default, which 

8 results in a lower borrowing cost. 

9 VI. SCE&G'S CREDIT RATING RISK 

10 Q. WHAT DOES FINANCIAL RISK MEAN IN THE CONTEXT OF THE 

11 FINANCIAL ANALYSIS DONE BY CREDIT RATING AGENCIES? 

12 A. From the point of view of the Company's creditors, financial risk addresses the ability of 

13 a company to make scheduled payments of interest and principal on its financial 

14 obligations. To assess a company's ability to make these payments, the credit rating 

15 agencies evaluate certain financial ratios to determine whether the company has sufficient 

16 levels of cash flow to cover its interest expense and to repay the principal amount of its 

17 debt in the future. The credit rating agencies also evaluate the relative amounts of debt 

18 and equity in the capital structure to determine whether a company is appropriately 

19 capitalized given its business risk profile. 

20 Q. IS FINANCIAL RISK TO DEBT HOLDERS THE SAME AS FINANCIAL RISK 

21 TO EQUITY HOLDERS?




Page 150fl9 


A. 

No. Financial risk from an equity investor's point of view is different. Financial risk is 

2 

3 

4 

5 

6 

7 

8 

the risk resulting from the fact that debt holders are paid first before any payments can be 

made to equity holders. Credit ratings are focused upon whether there is sufficient cash 

flow to make the required interest and principle payments on debt, but credit ratings are 

not a measure of the adequacy of cash flow to equity holders. Of course, a higher ROE 

provides higher cash flow to support the Company's credit rating, but an investment 

grade credit rating itself is not evidence that the allowed ROE is adequate compensation 

for the business and financial risk being borne by the equity holders. 

9 Q. 

HOW DO RATING AGENCIES 

ASSESS CASH FLOW? 

10 A. 

11 

12 

13 

The two primary cash flow metrics used by all ofthe credit rating agencies to assess 

financial risk are the ratio of Funds from Operations ("FFO") to Interest Expense 

("FFO/Interest") and the ratio of Funds from Operations to Total Debt ("FFOlTotal 

Debt"). 

14 Q. 

HOW DO RATING AGENCIES DETERMINE FFO? 

15 A. 

16 

FFO is computed by taking Cash from Operations from the company's Statement of Cash 

Flows and adding to that, changes in Working Capital to get a true sense of the cash 

17 

provided by the company's operations. 

The two largest income statement items that are 

18 

19 

20 

21 

included in FFO are net income and depreciation expense. The higher a company's net 

income and depreciation expense, the higher a company's FFO will be. As a result, the 

authorized ROE and determinations regarding depreciable plant lives have a significant 

impact on the critical cash flow coverage ratios. The more debt and other fixed-charge



Docket ER10· ·000 

Page 16 of 19 

Exhibit No. seE-1 

contractual obligations that a company has, the higher the adjusted interest expense and 

2 

3 

4 

5 

total adjusted debt and the lower the cash flow coverage ratios. Bond rating agencies 

closely analyze these ratios in setting bond ratings for publicly issued debt. In reviewing 

these credit measures, rating agencies look at historical and projected ratios. They 

detennine the credibility of the projections and the assumptions underlying them. 

6 Q. 

7 

HOW DOES A COMPANY'S CAPITAL STRUCTURE AFFECT ITS CREDIT 

RATING? 

8 A. 

9 

10 

II 

12 

13 

14 

IS 

16 

The ratio of Total Debt to Total Capitalization provides a long-tenn measure of a 

company's financial risk. In general, if a company has more debt, it is considered to be 

more financially risky. As the level of debt in the capital structure increases, generally 

the level of interest expense that must be serviced increases and that requires higher 

levels of operating cash flow to produce adequate levels of interest coverage. The greater 

the financial leverage or fixed-charge obligations that a company has, the more volatile is 

the company's net cash flow after financing costs and the riskier the company is 

financially. For regulated industries, a lower equity ratio will generate less cash flow 

assuming the equity return is held constant. 

17 Q. 

WHAT ARE SCANA'S CASH FLOW METRICS 

TODAY AND HOW ARE 

18 

THOSE METRICS 

VIEWED BY RATING AGENCIES? 

19 A. 

SCANA's FFO/Interest 

coverage is 3.4x and its FFOlTotal Debt ratio is 13.8%; its Total 

20 

21 

Debt/Total Capital ratio is 62.5%. This is viewed by the rating agencies as a very 

aggressive financial risk profile. According to S&P's most recent ratings report, "The



Docket ERIO-_-OOO 

Page 170fl9 


large capital spending program contributes to the aggressive financial risk profile and 

2 

3 

4 

5 

6 

7 

8 

9 

10 

II 

12 

necessitates not only a balanced funding approach but, importantly, timely rate relieffor 

both the nuclear construction to collect a cash return on construction work in process, but 

also through base rate relief to address the ongoing capital spending needs of the 

remaining company. Absent such relief, the financial profile can weaken further, placing 

additional downward pressure on ratings, even after accounting for the company's plan to 

fund a portion of these capital expenditures with equity issuances." See Exhibit SCE-5. 

S&P and Fitch gave SCANA a "stable" outlook, but S&P qualified that outlook by 

stating that it incorporated expectations that the adjusted FFOlInterest coverage would be 

no less than 3.5x, the adjusted FFO/Total Debt ratio would be between 14% and 15% and 

that the adjusted Total Debt/Total Capital ratio would begin to moderate from the 62.5% 

level at the end of 2008 as a result of retained earnings and proposed equity issuances to 

13 

support the construction program. 

S&P further stated that "Ratings could be lowered if 

14 

15 

16 

17 

18 

19 

credit metrics underperform expectations principally as a result of waning regulatory 

support resulting in delays for the recovery of unanticipated capital expenditures for the 

nuclear construction or schedule delays that are deemed imprudent with associated costs 

not recovered. Therefore, FFO to interest coverage of less than 3.0x, FFO to total debt of 

lower than 14%-15% and debt leverage that increases above current levels of about 

62.5% are pressure points towards lower ratings." See Exhibit SCE-5. 

20 Q- 

21 

WHAT ARE THE IMPLICATIONS OF THE STATE OF THE MARKETS TO 

THIS RATE PROCEEDING?



Docket ERIO·_·OOO 

Page 180fl9 


A. 

Investor interest in SCE&G greatly depends on our credit and that, of course, is affected 

2 

by the perception of the support of regulators for our company and industry, as well as 

3 

the returns granted the Company in rate proceedings. 

This link is true in normal 

4 

5 

6 

7 

economic environments, but is especially true during these uncertain economic times 

where investors will most certainly invest in a particular corporation such as ours, only 

when the risks are known, measurable and low (relative to the markets) and the rewards 

(returns) support the heightened risks of the current market environment. 

8 Q. 

WHAT CAPITAL STRUCTURE DO YOU PROPOSE BE USED IN THE 

9 

FORMULA 

RATE IN THIS FILING? 

10 A. 

The proposed formula relies on SCE&G's actual capitalization calculated from financial 

II 

data reported annually in the Company's FERC Form No.1. 

The current capital structure 

12 

is 49.75% oflong-term 

debt; 48.22% of common equity; and 2.03% of preferred stock. 

13 Q. 

14 

WHAT ARE THE COST RATES TO BE APPLIED 

STRUCTURE? 

TO THIS CAPITAL 

15 A. 

16 

17 

18 

19 

20 

The cost rate for long term debt currently is 5.01%. The cost rate for the preferred stock 

is currently 6.36%. These cost rates will be recalculated each Rate Year by the formula. 

While SCE&G's Witness Vilbert's testimony supports an ROE of 11.5%, the Company is 

willing to accept an ROE of only 11.3% in order to avoid suspension and a hearing. The 

ROE component of the formula is a fixed cost rate that, upon approval by the FERC, can 

only change in the future as a result of a Section 205 or 206 filing. The proposed formula



DocketER10-_-000 

Page 190f19 

Exhibit No. SCE- J 

1 calculates the overall cost of capital rate ("ROR") each time the formula rate is re- 

2 populated with Form No.1 data; currently the ROR is 8.07%. 

3 Q. DOES THIS COMPLETE YOUR TESTIMONY? 

4 A_ Yes it does.


AFFIDAVIT 

COUNTY OF LEXINGTON 

STATE OF SOUTH CAROLINA 

) 

) 

) 

Jimmy Addision, being duly sworn, deposes and states that the attached are his sworn 

testimony and exhibits, and that the statements contained therein are true and correct to the best 

of his knowledge, information and belief. 

SWORN AND SUBSCRIBED BEFORE ME, 

this 22 00 day of December, 2009 

~ 

NOtaIir 

C~ 

~ 

My Commission Expires: t? I o't) II-::r.




EXHIBIT NO. SCE-2 

S&P PUBLICATION 

TITLED 

HOW RETURNS ON EQUITY FACTOR INTO U.S. UTILITIES' 

CREDITWORTHINESS


Exhibit No. seE-2 

How Returns On Equity Factor Into 

U.S. Utilities' Creditworthiness 

Primary Credit Analyst: 

Gerrit Jepsen, CFA. New yo~ 111212-438-2529; gerrit,jepsen@Standardandpoors.com 

Table Of Contents 

Rate-Case Issues 

Regulatory Mechanisms 

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Use,IOisclaimer 00 U'If: lasl page.


Exhibit No. SCE-2 

How Returns On Equity Factor Into U.S. 

Utilities' Creditworthiness 

Although a higher authorized return on equity (ROE) may theoretically improve a utility'S cash flow, a company's 

ability to actually earn the authorized ROE is more important for overall creditworthiness. The ability to earn an 

authorized ROE depends on adjustments included in rate·case decisions, and Other regulatory mechanisms such as 

fuel-adjustment 

Furthermore, 

clauses. 

Standard & Poor's Ratings Services distinguishes between the effect of regulatory decisions on 

earnings and cash flow, which may differ. In a rate case, decisions beyond setting the ROE can p:tovide an 

opportunity 

for a utility to earn the authorized ROE or result in earnings erosion. In some cases, the inability to earn 

the authorized ROE could occur immediately after a rate case decision. 

Regardless of the authorized ROE, a utility'S cash flow could be compromised and its financial profile could decline 

from escalating costs such as pension and health care expenses, and much higher than historical levels of capital 

spending. Between rate cases, regulatory mechanisms that provide recovery of costs can support a utility's ability to 

earn its authorized ROE. As utilities seek recovery of these increasing costs in rates and higher capital spending 

levels, lower ROEs may be acceptable if other costs are recoverable and the authorized ROE can actually be earned. 

This article, which is Part I of two articles, analyzes ratemaking factors that weigh upon a utility's creditworthiness. 

Part II, to be published within the next several weeks, will illustrate the points made in Part I through an analysis of 

eight utilities--four that appear to have earned at least their authorized ROEs and four utilities that have not earned 

their authorized equity returns. 

Rate-Case 

Issues 

When commissions set a utility's rates in a rate case, many items may be considered that can strengthen or weaken 

the utility'S ability to at least earn its authorized return. The ROE authorization is only one component. Other 

regulatory decisions in rate cases that can result in a utility earning or not earning its authorized ROE include: 

• The revenue sources and the revenue levels used for setting rates. Commissions that exclude various revenue 

sources or assume lower customer growth when setting rates may provide a better opportunity for a utility to 

earn its authorized ROE. Wholesale sales to municipalities, cooperatives, and other investor-owned utilities may 

be excluded from the calculation of retail rates and therefore are not included in the regulated ROE calculation. 

Although a utility may not earn its authorized retail ROE, the total utility ROE could be higher because of the 

inclusion of cash flow from nonretail sales. Alternatively, a commission may include sales to non retail customers 

when setting rates, making it likelier that the earned retail ROE and total utility ROE will be similar. Also, 

because a utility may be able to' sell incremental power at prices above the base-rate levels, its overall ROE could 

be higher than the retail-only ROE. 

• Operation and maintenance expenses. Expenses such as wages, pensions, insurance, rents, and health care can 

affect a utility'S opportunity to earn the authorized ROE. If rate recovery of these expenses is lower than actual 

levels, rates may not provide a utility the ability to earn the authorized ROE and if expenses increase faster than 

forecast, earnings could also erode, resulting in lower ROEs. 

• Fuel and purchas!!d-power expenses included in base rates. The exclusion of higher fuel and purchased-power 

Standard & Poor's RatingsDirect I June 14. 2005 

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2



How Returns On Equity Factor Into U.S. Utilities' Creditworthiness 

costs in base rates could impair a utility's ability to earn the authorized ROE. Commissions may set rates based 

on historical levels that are lower than actual amounts, reducing the ability to earn the authorized ROE because 

additional fuel and purchased-power 

income. 

costs could be incurred without rate recovery, ultimately lowering net 

• Depreciation expense. Higher depreciation expense provides timely rate recovery of inve~tments and stronger cash 

flow, but lower earnings and earned ROEs. If depredation 

match the useful lives of plant and equipment, and cash flow will be lower. 

levels are low, rate recovery of investments may not 

• Taxes other than income taxes. Property taxes and other taxes could rise above the level in rates, and result in 

earnings and cash flow erosion. 

• Return on rate base. The weighted average cost of capital (WACC), or overall return, multiplied by a utility's rate 

base results in an authorized return on rate base from which interest expense and dividends are paid. Multiple 

variables in this calculation can affect a utility's ability to earn its authorized ROE. The return can be lowered by 

relying on a WACC 

(overall return) that is calculated with interest rates lower than actual rates, a lower ROE, or 

a capital structure that may have a lower common equity component, 

all of which can affect a utility's ability to 

earn the authorized ROE. If a publicly traded utility issues additional equity after a rate case, the ability to earn 

its authorized ROE will be hindered. 

• Rate base. Another component of the return calculation is the rate-base level. If a commission relies on an 

outdated rate base or excludes plant from rate base if not "used and useful" when.setting rates, a utility could 

almost immediately experience earnings and cash flow erosion. In addition, if recovery of carrying costs on 

capital spending is disallowed unti] after the plant is considered useful, incremental earnings erosion will occur. 

Alternatively, cash flow and earnings would be strengthened if a commission allows the rate base to be updated. 

• Income taxes. If actual income taxes are higher than the level used to set rates, earnings and the ROE will be 

lower. 

• Test period. Partly or fully forecast test periods reduce regulatory lag by providing for recovery of estimated 

expenses that may be incurred in the near term. Using a historical test period without updates makes it more 

difficult to earn the authorized ROE because expenses may have already increased during the rate case (which can 

take many months to complete), resulting in cost recovery that is too low even after new rates are set. Credit 

quality benefits from forecast test periods and less so from updated historical test periods. 

• Other disallowances. A commission could disallow recovery of an acquisirion premium, resulting in lower 

earnings and cash flow. 

• Rate design. A utility's actual rate structure can affect a utility!s ability to earn its authorized ROE. Cash flows 

are more stable and earnings more predictable when a higher percentage of a utilitis 

costs are recoverable 

through the fixed charge paid by customers regardless of electricity used and the first-rate block of typical 

monthly energy usage. 

• Timeliness. The faster a commission approves new rates, the quicker the improvement in cash flow and the better 

a utility'S opportunity 

to earn its authorized ROE due to reduced regulatory lag. If a final ruling cannot be issued 

in a timely manner, a commission's ability to issue an interim rate ruling provides rate relief and lowers financial 

uncertainty about ultimate rate recovery. 

Regulatory Mechanisms 

Certain regulatory mechanisms may be available to commissions that, if used, can strengthen a company's cash 

flow. Earnings and cash flow should improve if such mechanisms are used. Among the items that could require 

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How Returns On Equity Factor Into U.S. Utilities' Creditworthiness 

incremental recovery between rate cases are: 

• Fuel and purchased-power COsts. Recovery of fuel and purchased~power costs through a surcharge mechanism 

can improve a utility's ability to earn its authorized ROE. The more frequently adjusted, the less working capital 

required while the costS are deferred for future recovery. If partial or full rate recovery is disallowed or such a 

mechanism is not used, liquidity could be restricted and cash flow reduced. 

• Return on construction work in progress (CWIP). Provides for rate recovery of a return on new plant (carrying 

costs) while it is being built, assuring more stable cash flow through a construction 

CWIP reduces the size of the rate increase necessary after the construction 

carrying costs were recovered during construction, 

cycle. In addition, a return on 

of the new plant is complete because 

and not deferred for future recovery. Even more supportive is 

rate recovery of carrying costs through tracker mechanisms that may also provide for recovery, outside of a rate 

case, of depreciation, 

operations, and maintenance expenses after the plant is "used and useful." Certain states 

are allowing such tracker mechanisms to be used for recovery of pollution-control 

equipment. 

• Pension and other post-retirement benefit costs. Earnings are more likely to reach authorized levels between rate 

cases when utilities can recover pension costs not currently in base rateS through a pension-adjustment 

mechanism. 

• Storm damages. Utilities may receive recovery of storm damage costs through a special surcharge, which would 

increase cash flow and earnings. 

• Other costs. A surcharge mechanism may be used to recover unusual expenses such as those related to a utility'S 

participation 

in regional transmission organizations. 

• Weather normalization. A weather-normalization clause is primarily used to adjust rates (but not commodity 

prices) for natura) gas utilities that are exposed to swings in earnings and cash flow from weather volatility. The 

benefits of this clause are realized during the winter heating season when weather may be warmer than expected, 

but the customer is billed as though weather were normal, providing for more stable cash flow. Utilities without 

weather-normalization clauses may be unable to fully cover operating costs during warmer-than-normal winter 

weather. Standard & Poor's considers weather-normalization clauses as beneficial for creditworthiness and more 

likely to allow a utility to earn its authorized return. 

Standard & Poor's Rating_Direcl I June 14.2005 4 

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their third-party providers have exclusive proprietary rights in the inlormahon. including ratings. credit-related analyses and data, provided herein. This information shall nol 

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DOCKET ERIO-_-OOO 


S&P'S, MOODY'S AND FITCH'S DOWNGRADES OF SCE&G


Exhlibit No. SCE-3(A) 

Research Update: 

SCANA Corp. Downgraded To 

'BBB+' From 'A-' On Planned 

Nuclear Plants Construction 

Primary Credit Analyst: 

Dimitri Nikas. New Yorl


Exhibit No. SCE-3(A) 

Research Update: 

SCANA Corp. Downgraded To 'BBB+' From 

'A-' On Planned Nuclear Plants Construction 

Rationale 

On April 22, 2009, Standard & Poor's Ratings Services lowered the corporate 

credit ratings on SCANA Corp., South Carolina Electric & Gas Co. (SCE&G), and 

Public service Co, of North Carolina (PSNC) to 'BBB+' from 'A-'. The outlook 

is stable. See end of release for complete list of ratings. 

The rating action reflects an increase in business risk associated with 

SCE&G's plans to build two new nuclear units combined with the need to source 

a meaningful amount of external financing in order to complete the projects. 

While we still consider the business risk profile for the consolidated 

enterprise as excellent in our assessment, the expected deterioration and 

pressure on the financial risk profile are not consistent with our 

expectations for lA' category ratings. 

SCE&G will build the two new nuclear units in partnership with the South 

Carolina Public Service Authority (Santee Cooper, AA-/Stable/--). SCE&G will 

own 55% of the two new units at an estimated cost of about $5.4 billion ($6.3 

billion after including transmission costs) which includes forecasted 

inflation, owner's costs, and various contingencies. The aggressive 

consolidated financial risk profile in part reflects the substantial amount of 

financing for the project, especially in light of SCANA's total asset size at 

Dec. 31, 2008 of about $11.5 billion. The proposed project introduces 

significant construction and financing risk which places considerable pressure 

on the consolidated credit profile of SCANA and necessitates that all 

remaining aspects of the business perform satisfactorily in order to provide 

support and preserve the current ratings. 

The new units are Westinghouse AP1000 designs, each with 1,117MW of 

generation capacity and anticipated commercial operation dates of 2016 and 

2019. The new units, while evolutions of existing plant designs, have not been 

built before and have significant first-of-a-kind risk. SCE&G has received the 

necessary regulatory approvals, including a Base Load Review Order that 

approves the proposed construction budget and schedules and includes both 

scheduling and financial contingencies. To supplement the regulatory 

framework, which provides for recovery of financing costs during construction, 

periodic progress reviews, inability of future commissions to review 

previously approved capital expenditures for prudency, and ability to recover 

the abandoned investment, SCE&G has entered into an engineering procurement 

and construction contract with Shaw and Stone & Webster to design and build 

the two units. Without the regulatory framework that provides support to the 

project, business risk would be significantly higher that would place even 

more pressure on the ratings. 

SCANA's business risk profile is excellent, characterized by operations 

in generally supportive regulatory environments in North Carolina and South 

Carolina that provide for timely recovery of fuel costs through adjustment 

Standard & Poor's RatingsDirect I April 22,2009 2 

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Research Update: SCANA Corp. Downgraded To 'BBB+' From 'A-' On Planned Nuclear Plants Construction 

mechanisms and adequate allowed returns; attractive markets with above-average 

customer growth; some operating diversity with a presence in two states; and a 

favorable operating record for its electricity generation facilities. SCANA's 

regulated operations account for about 90% of consolidated cash flows. 

SCANA's consolidated financial risk profile is aggressive. For 2008, 

adjusted funds from operations were $714.3 million and adjusted total debt was 

$5.16 billion. Credit metrics have weakened from prior years' levels, in large 

part due to a significant increase in debt to fund capital spending which 

totaled $914 million in 2008. Adjusted funds from operations (FFO) interest 

coverage was 3.4x, adjusted FFO to total debt was 13.8% and adjusted total 

debt to total capital was 62.5%. The expected capital spending program is 

significant with about $1.2 billion annually in 2009 and 2010 and $1.4 billion 

in 20'11, a material portion of which will be for the proposed nuclear plants. 

The large capital spending program contributes to the aggressive financial 

risk profile and necessitates not only a balanced funding approach but, 

importantly, timely rate relief for both the nuclear construction to collect a 

cash return on construction work in process, but also through base rate relief 

to address the ongoing capital spending needs of the remaining company. Absent 

such relief, the financial profile can weaken further, placing additional 

downward pressure on ratings, even after accounting for the company's plan to 

fund a portion of these capital expenditures with equity issuances. 

Liquidity 

SCANA's liquidity is adequate to meet capital sp~nding and other needs. 

SCANA's liquidity consists of $1.1 billion in revolving credit facilities 

(SCANA: $200 million, SCE&G: $650 million; and PSNC: $250 million) that expire 

in 2011 and which had $564 million still undrawn. Liquidity also benefits from 

$272 million of cash on hand as of Dec. 31, 2008. Debt maturities are 

manageable and somewhat mitigate refinancing risk at least over the 

intermediate tem, with $144 million in 2009, $25 million in 2010, about $546 

million in 2011/ $275 million in 2012, and $167 million in 2013. 

Outlook 

The stable outlook on SCANA incorporates expectations that the proposed 

nuclear construction proceeds on schedule and on budget within the 

SCPSC-approved scheduling and budget mechanism. In addition, the stable 

outlook incorporates expectations that the financial risk profile will remain 

aggressive with adjusted FFO to interest coverage of no less than 3.Sx, 

adjusted FFO to total debt of 14% to 15%, and adjusted total debt to total 

capital that will begin to moderate from the end of 2008 levels of 62.5% as a 

result of retained earnings and proposed equity issuances to support the 

construction program. Ratings could be lowered if credit metrics underperform 

expectations principally as a result of waning regulatory support resulting in 

delays for the recovery of unanticipated capital expenditures for the nuclear 

construction or schedule delays that are deemed imprudent with associated 

costs not recovered. Therefore, FFO to interest coverage of less than 3.0x, 

FFO to total debt of lower than 14%~15% and debt leverage that increases above 

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Research Updat" SCANA Corp. Downgraded To 'BBB+' From 'A-' On Planned Nuclear Plants Construction 

current levels of about 62.5% are pressure points towards lower ratings. 

Standard & Poorls does not currently contemplate a higher rating during the 

construction period, given the size and scale of the project. 

Ratings List 

Downgradedi CreditWatch/Outlook Action; Ratings Affirmed 

SCANA Corp. 

Corporate Credit Rating 

Senior Unsecured 

To 

BBB+/Stable/-- 

BBB 

Public Service Co. of North Carolina Inc. 


BBB+!Stable!A-2 

Senior Unsecured BBB+ 

From 

A-!Negative!-- 

BBB+ 

A-!Negative!A-2 

A- 

South Carolina Electric & Gas Co. 


Preferred Stock 

BBB+!Stable!A-2 

BBB- 

A-!Negative!A-2 

BBB 

Ratings 

Affirmed 

South Carolina Fuel Co. 

Short-term Corporate Credit Rating A-2 

Public Service Co. of North carolina Inc. 

Commercial Paper A-2 

South Carolina Electric & Gas Co. 

Senior Secured 

Senior Secured 

Recovery Rating 

A 

A- 

1 


South Carolina Fuel Co, 


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Exhibit No. SCE-3(8) 

Global Credit Research 

Rating Action 

14 JUL 2009 

Rating Action: SCAN A Corporation 

Approximately $5 billion of debt affected 

New YOrl



expectations over the longer-term horizon. Moody's incorporates a view that PSNC will continue to produce 

key financial credit metrics, including RCF/Debt and EBIT /Interest coverage of 15% and 3.5x, respectively, 

on a sustainable basis. 

The negative rating outlooks for SCANA, SCE&G and PSNC reflect our concerns regarding the elevated risk 

profile of the consolidated enterprise, primarily associated with its new nuclear construction plans but also 

potential carbon costs. Ratings could be downgraded further if the financial profiles of both SCANA and 

SCE&G continue to exhibit declining cash flow in relation to total debt; if there are significant cost over-runs 

or construction delays associated with the VC Summer nuclear expansion or if regulatory and political 

support for the project began to show some stress. Depending on how the corporate finance policies evolve, 

there is also the possibility that the rating relationship or notching between SCANA and SCE&G may begin to 

widen. 

Moody's last rating action for SCANA, SCE&G and PSNC occurred on December 4, 2007 when the ratings of 

all family entities were downgraded by one notch due to expectations of a weakening financial profile. 

The principal methodology used in rating the utilities was the Rating Methodology: Global Regulated Electric 

Utilities. It can be found at www.moodys.comin the Credit Policy & Methodologies directory, in the Ratings 

Methodologies subdirectory. Other methodologies and factors that may have been considered in the process 

of rating this issuer can also be found in the Credit Policy & Methodologies directory. 

SCANA is an electric and gas utility holding company headquartered 

in Columbia, South Carolina. 

Downgrades: 

..Issuer: Berkeley (County of) SC 

.... Senior Unsecured Revenue Bonds, Downgraded to a range of Baa2 to Baa1 from a range of Baa1 to A3 

..Issuer: Colleton & Dorchester (Cntys of) SC 

....Senior Secured Revenue Bonds, Downgraded to A3 from A2 

..Issuer: Fairfield (County of) SC 

....Senior Secured Revenue Bonds, Downgraded to A3 from A2 

..Issuer: Richland (County of) SC 

.... Senior Secured Revenue Bonds, Downgraded to A3 from A2 

..Issuer: SCANA Corporation 

....Issuer Rating, Downgraded to Baa2 from Baa1 

....Senior Unsecured Medium-Tenm Note Program, Downgraded to Baa2 from Baa1 

....Senior Unsecured Regular Bond/Debenture, 

Downgraded to Baa2 from Baa1 

..Issuer: South Carolina Electric & Gas Company 

.Issuer Rating, Downgraded to Baa1 from A3 

....Multiple Seniority Shelf, Downgraded to a range of (P)Baa3 to (P)A3 from a range of (P)Baa2 to (P)A2


Exhibit No. SCE-3(B) 

....Preferred Stock Preferred Stock, Downgraded to Baa3 from Baa2 

....Senior Secured First Mortgage Bonds, Downgraded 

to A3 from A2 

....Senior Secured Shelf, Downgraded to (P)A3 from (P)A2 

..Issuer: South Carolina Jobs-Economic Development Auth 

....Senior Secured Revenue Bonds, Downgraded 

to A3 from A2 

Outlook Actions: 

..Issuer: Public Service Co. of North Carolina, Inc. 

...Outlook, Changed To Negative From Stable 

..Issuer: SCANA Corporation 

....Outlook, Changed To Negative From Stable 

..Issuer: South Carolina Electric & Gas Company 


..Issuer. South Carolina Fuel Company Inc . 


New York 

James Hempstead 

Senior Vice President 

Global Infrastructure Finance 

Moody's Investors Service 

JOURNALISTS: 212-553-0376 

SUBSCRIBERS: 212-553-1653 

New York 

William L. Hess 

Managing Director 

Global Infrastructure Finance 

Moody's Investors Service 

JOURNALISTS: 212-553-0376 

SUBSCRIBERS: 212-553-1653 

CREDIT RATINGS ARE MOODY'S INVESTORS SERVICE, INC,'S (MIS) CURRENT OPINIONS OF THE 

RELATIVE FUTURE CREDIT RISK OF ENTITIES, CREDIT COMMITMENTS, OR DEBT OR DEBT-LIKE 

SECURITIES, MIS DEFINES CREDIT RISK AS THE RISK THAT AN ENTITY MAY NOT MEET ITS 

CONTRACTUAL, FINANCIAL OBLIGATIONS AS THEY COME DUE AND ANY ESTIMATED FINANCIAL LOSS 

IN THE EVENT OF DEFAULT, CREDIT RATINGS DO NOT ADDRESS ANY OTHER RISK, INCLUDING BUT 

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SUITABILITY OF AN INVESTMENT FOR ANY PARTICULAR INVESTOR. MIS ISSUES ITS CREDIT RATINGS 

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AND EVALUATION OF EACH SECURITY THAT IS UNDER CONSIDERATION FOR PURCHASE, HOLDING, 

OR SALE. 

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and k;ancial reporting analYSis observations, if any, constituting part of the information contained herein are, and must be 

construe(i solely as, statements of opinion and not statements of fact or recommendations to purchase, sell or hold any 

securities. NO W.5,RRANTY, EXPRESS OR IMPLIED, AS TO THE ACCURACY, TIMELINESS, COMPLETENESS, MERCHANTABILITY OR 

FiTNESS fOR ANY PARTICULAR PURPOSE OF ANY SUCH RATING OR OTHER OPINION OR INFORMATION IS GIVEN OR MADE BY 

HOODY'S IN ANY FOR!>-1 OR HANNER WHATSOEVER. Eae!l ri1tii19 or other opinion must be weighed solely as one factor in any 

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(HeO) ilnd its wholly--owned credit rating agency subsidiary, Moody's Investors Service (MIS), also maintain policies and 

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Ur)rjer ttle heaclin9 "Sha['eholder Relations Corpori:lte Governance - Director and Shareholder Affiliation Policy."


Exhibit No. SCE-3(C) 

FitchRatin~ 

DIItf·mlll. _~~ 

Fitch: Info Center: Press Releases 

Fitch Downgrades SCANA & Subsidiaries' IDRs to '888+' 

25 Jun 2009 4: 11 PM (EDT) 

Ratings 

Fitch Ratings-New York-25 June 2009: Fitch Ratings has downgraded the Issuer Default Ratings (IDRs) of SCANA 

Corp. (SCANA) and its subsidiaries South Carolina Electric & Gas Co. (SCE&G) and Public Service Co. of North 

Carolina (PSNC) to '888+' from 'A-'. Fitch also downgraded the individual issue ratings one notch as shown in the 

list of rating actions at the end of this release. The short-term IDRs of SCANA, SCE&G and PSNC and commercial 

paper ratings of SCE&G, PSNC and South Carolina Fuel Company are affirmed at 'F2'. The Rating Outlook for 

each entity is Stable. 

The downgrades are driven by the financial pressure and increased business risk from SCE&G's plans to construct 

and finance wo nuclear generating units for service in 2016 and 2019, respectively, and a decline in credit quality 

measures over the past 18 months. SCE&G will own 55% of the two units at an estimated cost of $6.3 billion. The 

nuclear investment, together with maintenance capital expenditures of approximately $500 million annually, will 

more than double SCE&G's existing net investment in property plant and equipment. Expenditures are expected to 

peak in the years 2012 to 2014. Management expects to fund approximately 50% of the expenditures with new 

debt. 

The credit impact of the incremental debt burden is softened by legislation in South Carolina, the Base Load 

Review Act (8LRA), which permits utilities to recover capital costs, including a return on equity, during construction. 

Other risk mitigants include an EPC contract that fixes a portion of the plant cost and a substantial equity 

commitment. Although the credit quality of subsidiary PSNC is not directly affected by the events at SCE&G, the 

weakening consolidated credit quality of SCANA accounts for the lower rating for PSNC. 

Fitch has downgraded SCANA and its subsidiaries' ratings as follows: 

SCANA Corporation 

-lOR to '888+' from 'A-'; 

-Senior Unsecured debt to '888+' from 'A-'. 

SCE&G 

--lOR to '888+' from 'A-': 

--First Mortgage bonds to 'A' from 'A+'; 

-Senior Unsecured debt to 'A-' from 'A'; 

-Preferred Stock to '888+' from 'A-'. 

PSNC 

--lOR to '888+' from 'A-'; 

--Senior Unsecured debt to 'A-' from 'A'. 

Fitch has affirmed SCANA and its subsidiaries' 

ratings as follows: 


-Short-term lOR at 'F2'. 

SCE&G 

--Short-term lOR at 'F2'; 

--Commercial Paper at 'F2'. 

PSNC 

-Short-term lOR at 'F2'; 

-Commercial Paper at 'F2'. 

Contact: Robert Hornick +1-212-908-0523 or Jill Schmidt +1-212-908-0644, New York. 

Media Relations: Francoise Alos, Paris, Tel: +33 1 44 29 91 22, Email: francoise.alos@fitchratings.com.



Fitch's rating definitions and the terms of use of such ratings are available on the agency's public site, 

·www.fitchratings.com·.Publishedratings.criteria and methodologies are available from this site, at all times. Fitch's 

code of conduct, confidentiality, conflicts of interest, affiliate firewall, compliance and other relevant policies and 

procedures are also available from the 'Code of Conducf section of this site. 

Copyright © 2009 by Fitch, Inc., Fitch Ratings Ltd. and its subsidiaries.





COMPLETE LIST OF SCE&G'S AND SCANA'S 

CREDIT RATINGS AS OF JULY, 2009



PC>'\N""ER. FOR LIVING 

SCANA Corporation and Subsidiaries 

Security Credit Ratings 

As o(Juiv 14.2009 

Moody's(3) Standard & Poor's (\) Fitch (2) 


Issuer Rating/Corporate Credit Rating/Issuer Default Rating 

Senior Unsecured Debt (Medium-Tenn Notes) 

Rating Outlook 

Baa2 

Baa2 

negative 

BBB+ 

BBB 

stable 

BBB+ 

BBB+ 

stable 



Senior Secured Debt (First Mortgage Bonds) 

Senior Unsecured Debt 

Short-Tenn Debt (Commercial Paper) 



Baal 

A3 

Baal 

P-2 

Baa3 

negative 

BBB+ 

BBB+ 

A- A 

BBB+ A- 

A-2 F-2 

BBB- 

BBB+ 

stable 

stable 

South Carolina Fuel Company 

Short-Tenn Debt (Commercial Paper) P-2 

A-2 F-2 

PSNC Energy 


Senior Unsecured Debt 

A3 

Short-Tenn Debt (Commercial Paper) P-2 


negative 

BBB+ 

BBB+ 

A-2 

stable 

BBB+ 

A- 

F-2 

stable 

Recent Actions: 

(I) On April 22, 2009, S&P downgraded SCANA and its rated subsidiaries one notch with the exception of 

SCE&G Senior Secured Debt (First Mortgage Bonds). Short-tenn debt at rated subsidiaries remains at A-2. 

S&P also revised its long-tenn ratings Outlook from Negative to Stable. 

(2) On June 25, 2009, Fitch downgraded SCANA and its rated subsidiaries one notch and affinned all shorttenn 

ratings on SCANA and its rated subsidiaries to F-2. Fitch also revised its long-tenn ratings Outlook 

from Negative to Stable. 

(3) On July 14,2009, Moody's downgraded SCANA and South Carolina Electric& Gas Company (SCE&G) 

one notch. Short-tenn debt (Commercial Paper) ratings remain at P-2. Moody's affinned the ratings for 

PSNC and South Carolina Fuel Company (SCFC). Moody's also revised its long-tenn ratings Outlook 

from Stable to Negative for SCANA and its rated subsidiaries. 

SCANA Investor Relations




EXHIBIT 

NO. SCE-5 

COPIES OF SCE&G'S MOST RECENT RATINGS REPORTS FROM 

S&P, MOODY'S 

AND FITCH


Exb,ibit No. SCE-5(A) 

Summary: 


Primary Cred~ Analyst 

Dimitri Njkas, New York (1) 212·438-7807; dimitri_nikas@standardandpoors.com 

Table Of Contents 

Rationale 

Outlook 

www.standardandpoors.com/ratingsdirect 1 

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UselOlsclaimer ali Ihe 18$1page.



Summary: 


Credit Rating: 

B88+fStablefNR 

Rationale 

The ratings on Columbia, S.C.-based SCANA Corp. reflect the consolidated credit profiles of its two primary 

operating subsidiaries, South Carolina Electric & Gas Co. (SCE&G) and Public Service Co. of North Carolina Inc. 

(PSNC), and also incorporate the contributions of Carolina Gas Transmission Corporation (CGTC) and the 

company's Georgia retail gas marketing operations. 

SCANA has an excellent business risk profile, characterized by operations in generally supportive regulatory 

environments in North Carolina and South Carolina, attractive markets with above-average customer growth, some 

operating diversity with a presence in two states, and a favorable operating record for its electricity generation 

facilities. SCANA's regulated operations account for about 90% of consolidated cash flows. 

SCANA's largest subsidiary, SCE&G serves approximately 650,000 electric (1.7% increase over the 2007 level) and 

307,000 gas customers (1.3% increase over the 2007 level) in South Carolina and accounted for 77% of 

consolidated net income and 79% of cash from operations in 2008. PSNC serves approximately 468,000 gas 

customers (a 2.4% increase over the 2007 level) in North Catclina and accounted for 12 % of net income and cash 

flow. In the aggregate, the customer base consists mostly of residential and commercial customers, providing a 

measure of stability to revenues and cash flow. Customer growth is satisfactory despite the general slowdown in the 

national and local economies. 

Business risk for SCANA has increased primarily as a result of SCE&G's plans to build two new nuclear units in 

partnership with the South Carolina Public Service Authority (Santee Cooper, AA-/Stable!--). The units are 

Westinghouse APIOOOdesigns each with 1,117MWof generation capacity and anticipated commercial operation 

dates of 2016 and 2019. The new units, while evolutions of existing plant designs, have not been built before and 

have significant first-of-a-kind risk. SCE&G will own 55% of each of the units. SCE&G has received the necessary 

regulatory approvals, including a Base Load Review Order that approves the proposed construction budget and 

schedules and includes both scheduJing and financial contingencies. To supplement the regulatory framework that 

provides for recovery of financing costs during construction, periodic progress reviews, inability of future 

commissions to review prior years' capital expenditures for prudency, and ability to recover the abandoned 

investment, SCE&G has entered into an engineering procurement and construction contract with Shaw and Stone & 

Webster to design and build the rwo units. The cost for SCE&G's portion upon completion is estimated at about 

$5.4 billion ($6.3 billion after including transmission costs) and includes forecasted inflation, owner's costs and 

various contingencies. The proposed project introduces significant construction and financing risk which places 

considerable pressure on the consolidated credit prome of SCANA and necessitates that all remaining aspects of the 

business perform satisfactorily in order to provide support and preserve the current ratings. 

CGTC operates as a FERC-regulated, transportation~only, natural-gas transmission company, eliminating any 

exposure to commodity prices. 

Standard & Poor's RatingsDirect I April23,2009 2 

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Exhibit No. SCE-S(A) 

Summary: SCANA 

Corp. 

Through SCANA Energy, SCANA is exposed to retail gas marketing operations in Georgia, serving abour 460,000 

customers, including about 95,000 customers under a provider-of-last-resort arrangement that includes low-income 

and high credit risk customers. SCANA Energy will hold this role as the provider of last resort through August 

2009. Standard & Poor IS views this operation as having significantly higher business risk compared to the regulated 

utility operations, stemming from the potential for customers to leave SCANA Energy for alternative suppliers as 

well as the challenge of matching supply and demand without any regulatory recourse for cost under-recoveries. The 

latter risk is partly mitigated by a significant percentage of customers who are on variable pricing plans that adjust 

monthly to reflect current market prices. 

SCANA's consolidated financial risk profile is aggressive. For 2008, adjusted funds from operations 

(FFO) were 

$714.3 million and adjusted total debt was $5.16 billion. Credit metrics have weakened from prior years' levels, in 

large part due to a significant increase in debt to fund capital spending which totaled $914 million in 2008. 

Adjusted FFO interest coverage was 3.4x, adjusted FFO to total debt was 13.8% and adjusted total debt to total 

capital was 62.5%. The expected capital spending program is significant with about $1.2 billion annually in 2009 

and 2010 and $1.4 billion in 2011, a material portion of which will be for the proposed nuclear plants. The large 

capital spending program contributes to the aggressive financial risk profile and necessitates not only a balanced 

funding approach but, importantly, timely rate relief for both the nuclear construction 

construction 

to collect a cash return on 

work in process, but also through base rate relief to address the ongoing capital spending needs of the 

remaining company. Absent such relief, the financial profile C3n weaken further, placing additional downward 

pressure on ratings, even after accounting for the company's 

with equity issuances. 

plan to fund a portion of these capital expenditures 

Liquidity 

SCANA's liquidity is adequate to meet capital spending and other needs. SCANA's liquidity consists of $1.1 billion 

in revolving credit facilities (SCANA: $200 million, SCE&G: $650 million; and PSNC: $250 million) that expire in 

2011 and which had $564 million still undrawn. Liquidity also benefits from $272 million of cash on hand as of 

Dec. 31, 2008. Debt maturities are manageable and somewhat mitigate refinancing risk at least over the 

intermediate tern, with $144 million in 2009, $25 million in 2010, about $546 million in 2011, $275 million in 

2012 and $167 million in 2013. 

Outlook 

The stable outlook on SCANA incorporates expectations that the proposed nuclear construction proceeds on 

schedule and on budget within the SCPSC-approved scheduling and budget mechanism. In addition, the stable 

outlook incorporates expectations that the financial risk profile will remain aggressive with adjusted FFO to interest 

coverage of no less than 3.5x, adjusted FFO to total debt of 14% to 15%, and adjusted total debt to total capital 

that will begin to moderate from the end of 2008 levels of 62.5% as a result of retained earnings and proposed 

equity issuances to support the construction program. Ratings could be lowered if credit merrics underperform 

expectations principally as a result of waning regulatory support resulting in delays for the recovery of unanticipated 

capital expenditures for the nuclear construction or schedule delays that are deemed imprudent with associated costs 

not recovered. Therefore, FFO to interest coverage of less than 3.0x, FFO to total debt of lower than 14%-15% and 

debt leverage that increases above current levels of about 62.5% are pressure points towards lower ratings. Standard 

& Poor's does not currently contemplate a higher rating during the construction period, given the size and scale of 

the project. 

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3


Exhibit No. seE-SeA) 

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Analytic services provided by Standard & Poor's Ratings Services (Ratings Servicesl are the resul! of separate aclivjtjes designed to presetve the independence and objectivity . 

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sell any !reCurities or make any other investment decisions. Accordingly. any user of the informCition contained herein should not rely Ofl aoy credit rating Of other opinion 

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Standard & Poor's Rating.Direct I April 23.2009 4



Global Credit Research 

Credit Opinion 

16 JUL 2009 

Credit Opinion: South Carolina Electric & Gas Company 

Columbia, South Carolina, United States 

Ratings 

Category 

Outlook 

Issuer Rating 

First Mortgage Bonds 

Senior Secured Shelf 


Moody's Rating 

Negative 

Baal 

A3 

(P)A3 

Baa3 

Commercial Paper P-2 

Parent: SCANA Corporation 

Outlook 

Issuer Rating 


Negative 

Baa2 

Baa2 

South Carolina Fuel Company 

Inc. 

Outlook 

Negative 

Bkd Commercial Paper P-2 

Contacts 

Analyst 

James HempsteadlNew York 

William L. HesslNew York 

Phone 

212.553.4318 

212.553.3837 

Key Indicators


ExhibitNo.SCE-5(8) 

[1] 

South Carolina Electric & Gas Company LTM lQ 09 2008 2007 2006 

(CFO Pre- WIC + Interest) I Interest Expense 3.3 4.4 4.7 4.7 

(CFO Pre-W/C) I Debt 12% 18% 23% 23% 

(CFO Pre-W/C - Dividends) I Debt 8% 13% 18% 17% 

(CFO Pre-W/C - Dividends) I Capex 35% 63% 77% 105% 

Debt I Book Capitalization 49% 49% 43% 44% 

EBITA Margin % 23% 22% 21% 20% 

[1]All ratios calculated in accordance with the Global Regulated Electric Utilities 

Rating Methodology using Moody's standard adjustments 

Note: For definitions of Moody's most common ratio terms please see the accompanying 

User's Guide. 

Opinion 

Rating Drivers 

Expected decline in financial metrics over intermediate-term 

horizon 

New nuclear construction program significantly increases business and operating risk profile, a concern 

given the size of the investment relative to the size of the consolidated company 

Supportive regulatory environment is a significant credit benefit 

Corporate 

Profile 

South Carolina Electric and Gas Company (SCE&G, Baa1 issuer rating I negative outlook) is a 

vertically integrated electric and gas distribution utility which owns or operates approximately 5.8 GWs 

of generation capacity including a 67% interest in the approximately 950 MW VC Summer nuclear 

facility. SCE&G is a wholly owned subsidiary of SCANA Corp (SCANA, Baa2 senior unsecured I 

negative outlook). 

SUMMARY RATING RATIONALE 

SCE&G's Baa1 issuer rating primarily reflects the company's high degree of regulated electric and gas 

utility operations, the supportive political and regulatory environment in South Carolina and the overall 

financial and liquidity profile of the company. SCE&G is weakly positioned in the Baa1 rating category, 

primarily due to our views of an elevated business and operating risk profile. Ratings could be further 

pressured downward over the next 12 to 18 months given the company's significant amount of 

projected capital expenditures and infrastructure investment, largely attributable to its new nuclear 

development plans. The financing plans associated with these capital investment plans and resulting 

credit metric projections, will increasingly represent a critical ratings driver for the credit over the next 

several years. 

DETAILED RATING CONSIDERATIONS 

New Nuclear Generation Plans Raise Business Risk Profile 

While Moody's generally views investments into regulated rate base favorably, SCE&G's pursuit of 

constructing 2,234 MWs of nuclear generation, in cooperation with Santee Cooper (45% ownership), is 

beginning to significantly increase the overall business and operating risk profile of the company. In our 

opinion, SCANA has taken very few material steps to strengthen SCE&G's balance sheet on the front 

end of a very long construction cycle.



SCE&G has high activity levels associated with the early construction phase of V.C. Summer units 2 

and 3. Approximately 67% of the total plant design is complete (as of March 2009), various project 

milestones have been achieved and an expected $389 million (SCE&G's share) will be spent in 2009 

(including $38 million in contingency funds that can be carried forward, if unused). We believe the 

project will have roughly $3.0 billion in investment before the NRC's COL application is received. In our 

opinion, as these developments continue, SCE&G will increasingly become more fully committed to 

building the new nuclear plant and any "optionality" that may have existed to exit or reverse course will 

be foregone. 

Although there have been minor timing differences that have impacted spending, the project remains 

on track, as planned. In addition, the V.C. Summer expansion has been discussed as a finalist to 

receive U.S. Department of Energy nuclear loan guarantees, a potential credit positive depending on 

the terms and conditions of the ultimate structure. Regardless, it is unlikely that the project will be 

considered off-credit and I or off-balance sheet. 

Given the new nuclear program's progress, the business risk profile of the company is transforming. 

Although we find SCE&G's attempts to mitigate certain risks as beneficial to its credit profile - including 

certain EPC contract terms designed to limit price escalations and, most notably, positive recovery 

mechanisms associated with the Base Load Review Act (BLRA) - we note that the lengthy time period 

needed for construction results in execution risks related to delays, changing market conditions, shifting 

political and policy agendas and technological developments. Given the nature of these risks, we would 

expect the management to proactively strengthen the balance sheet and bolster liquidity sources, in 

order to solidify the Baa1 rating at SCE&G and the Baa2 rating at SCANA. 

For a more detailed discussion of our views regarding new nuclear generation, please refer to our 

reports entitled "New Nuclear Generation: Ratings Pressure Increasing" published in June 2009, "New 

Nuclear Generating Capacity: Potential Credit Implications for U.S. Investor Owned Utilities" published 

in May 2008 and "New Nuclear Generation in the United States: Keeping Options Open vs Addressing 

an Inevitable Necessity" published in October 2007. 

Financial Performance Expected to Weaken 

SCE&G's historical financial profile has been relatively stable over the last three years, producing CFO 

pre W/C to debt of approximately 21% and CFO Pre wlc to interest of roughly 4.6x, on average. By way 

of comparison, the southeastern A3 rated utility peers (comprised of 15 vertically integrated utilities 

located in the southeastern region of the U.S.), have averaged 27% and 5.8x debt and interest 

coverage, respectively, from 2006-2008; whereas the Baa1 peers averaged 19% and 4.1x. Moody's 

recently downgraded SCE&G to the Baa1 level, largely due to the financial profile being more 

appropriate for the Baa rating category. 

Given the continued deterioration in financial metrics (LTM March 2009 of 12% CFO pre W/C to debt 

and 3.1x CFO pre W/C to interest coverage) combined with an expected capital expenditure program in 

excess of $1 billion in each of the next three years, we expect the financial metrics to remain 

significantly below the above historical levels for the foreseeable future. In addition, given the nature of 

the capital expenditures (predominantly associated with the expansion of the V.C. Summer nuclear 

facility) and the increased risk profile of the company, SCE&G's financial profile will have to be more 

robust than historical levels, in order to maintain a Baa1 rating, on an unsecured basis. 

Political and Regulatory Support Essential 

Given the higher risk nature of SCE&G's business profile, in conjunction with the construction ofV.C. 

Summer units 2 and 3, there is an even greater need for timely and adequate rate relief for the 

company. From a credit perspective, Moody's views the political and regulatory environment in South 

Carolina favorably. The 2007 legislation referred to as the Base Load Review Act (BLRA) allows for the 

ongoing recovery of financing costs associated with the construction of new base load generation, 

including new nuclear plants, subject to the utility meeting certain conditions. 

In March, SCE&G filed its first quarterly report under the BLRA in association with the nuclear build. In 

the report, SCE&G details the progress and updated schedules of plant construction and costs, in 

addition to other information that the regulatory staff may require. According to the company's SEC



Form 10-K, under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to 

incorporate any nuclear construction work-in-progress incurred. Requested rate adjustments will be 

based on SCE&G's updated cost of debt and capital structure and on an allowed return on common 

equity of 11%. On February 11, 2009, the SCPSC approved the initial rate increase of $7.8 million or 

0.4% related to recovery of the cost of capital on project expenditures through June 30, 2008. The 

company is currently earning a return on the capital employed for the nuclear project, a credit positive. 

We do not incorporate a view that 100% of SCE&G's new nuclear investments are "guaranteed" 

recovery. Instead, we believe that should the project experience adverse challenges and lor needs to 

be abandoned, that the prospect for recovery would result in a lengthy legal and regulatory situation. 

At this time, we observe that as the nuclear construction progresses, the nature of the implementation 

and support of the BLRA will be key to SCE&G's ongoing credit profile. We expect that the BLRA and 

the Public Service Commission of South Carolina (SCPSC) will provide adequate and timely recovery 

of the costs associated with the expansion of the V.C. Summer unit into the current rate base? of the 

company. Should that view change or difficulties in recovering costs arise, so too could the ratings of 

SCE&G. 

As SCE&G (Prime-2 short-term rating) continues to move ahead with its significant investment 

program, we believe the company will not generate enough cash flow from operations to cover its 

planned capital expenditures. In addition, with SCANA management having reiterated its intent to 

maintain a dividend payout policy that reflects its projected long term earnings growth expectations, the 

parent company will continue to rely on up-stream dividends (roughly $170 million) from its principal 

subsidiary, SCE&G. While contractual debt maturities are modest over the next couple of years, the 

combined impact of the above factors exposes SCE&G to a greater dependency on external sources of 

capital for meeting its funding requirements which could also negatively impact its liquidity. 

SCE&G has access to $650 million of consolidated credit facilities ($400 million at SCE&G and $250 

million at South Carolina Fuel Company). These credit facilities, maturing in 2011, provide back up 

support to both companies' commercial paper programs (SCFC's CP program is guaranteed by 

SCE&G). These facilities do not contain any material adverse change language for subsequent 

borrowings but do include a debt to capitalization financial covenant (not to exceed 70%). As of March 

31, 2009, SGE&G had sufficient headroom available under the financial covenant. 

For the latest twelve months ended March 31, 2009, SCE&G generated approximately $413 million in 

cash flow from operations, invested roughly $779 million and made an upstream dividend payment to 

its parent, SCANA, of roughly $172 million, resulting in $538 million of negative free cash flow. This 

compares to $481 million and $222 million of negative free cash flow for the years ended 2008 and 

2007, respectively. 


The negative rating outlook incorporates our view that SCE&G's prospective credit metrics will continue 

to be pressured from its historical levels, most likely remaining in the mid-teen's range on a cash flow to 

debt basis. The negative outlook also reflects and captures the increasing business risk profile, 

primarily due to the magnitude of the new nuclear construc;tion program and the significant negative 

free cash flow that is commensurate with such an undertaking. The negative outlook does take into 

consideration the supportive regulatory and political environment in South Carolina. 

What Could Change the Rating - Up? 

Rating upgrades are unlikely over the near to intermediate term horizon due to our expectation that 

SCE&G will find it challenging to improve its key financial credit metrics to a level that justifies a ratings 

upgrade due to the company's significant capital expenditure plans and rising business risk profile. 

What Could Change the Rating - Down? 

We believe the company's heightened business risk profile can be reasonably well mitigated if the 

company's financial profile was more reflective of the average financial profile for peer companies that



produce key cash fiow related credit metrics of at least 4.0x interest and at least 20% of total adjusted 

debt outstanding in order to avoid additional negative ratings actions. The negative ratings outlook 

reflects some of our concerns with respect to SCE&G's ability to achieve and maintain those levels. 

Ratings could also be pressured downward if there was an adverse change to the degree of support 

that the South Carolina legislature and/or the SCPSC provides to SCE&G for prudently incurred cost 

recoveries, or if the company experienced significant delays or problems with the construction of V.C. 

Summer units 2 and 3. 

Rating Factors 


Select Key Ratios for Global Regulated Electric 

Utilities 

Rating » t Aa LAaiA + A I Baal Baal Ba I Ba 

Level of Business Risk "IMedluml Low IMedlumlLowJMediumjLow jMediuml Low 

CFO pre-W/C to Interest (x) [I] >6 >5 3.5-6.0 3.0- 2.7-5.0 2-4.0 22 22-30 12-22 13-25 5-13 20 13-25 9-20 8-20 3-10



securities. NO WARRANTY, EXPR.ESS OR IHPLlED, AS TO THE ACCURACY, Tlf>1EllNESS, COMPLETENESS, MERCHANTABILI1Y OR 

FITNESS FOR ANY PARTICULAR PURPOSE OF ANY SUCH RATING OR OTHER OPINION OR INFORMATION IS GIVEN OR MADE BY 

1'1()QDV'S IN ANY FOR!'>1OR f\1ANNER WHATSOEVER. Each rating or other opinion must be weighed solely as one factor in any 

investment C!ecisior, made by or or: bel-;aif of any user of the 'nfonnation contained herein, and each such user must accordingly 

make its own study and evaluation of each security and of each issuer and guarantor of, and each provider of credit support for, 

each security that it lTIay consider pur-chasing, Ilo;dillg or seiling. 

MOODY'S hereby discloses t.hat (rlZJ5t issuers of: debt securities (including corporate and municipal bonds, debentures, notes and 

commercial paper) and preferred stock rateci by MOODY'S have, prior to assignment of any rating, agreed to pay to MOODY'S 

for appraisal and rating services rendered by it fees ranQiflg fr-om $1,500 to approximstely 52,400,000. Moody's Corporation 

(Heel) 0nd its wholiy-owned CECCHi" rating ag


Exhibit No. seE-SIC) 

Corporates 

Global Power 

U.S. and Canada 

Credit Analysis 

South Carolina Electric & Gas 

Company 

Subsidiary 

of SCANA Corporation 

Ratings 

Security Class Current 

Rati 

Issuer DefauLt Rating 

AM 


AM 

Outlook 

Stable 

Financial Data 

South Carolina Electric & Gas CO. 

($M;!.) 

LTM 

Ended 

3/31/09 

Year 

Ended 

12/31/08 

Revenue 

Gross Margin 

Cash flow from 

Operations 

Operating EBITDA 

TotaL Debt 

TotaL Capitalization 

ROE (%) 

(APEX/Depreciation 

(x) 

Analysts 

Robert Homick 

+ t 2 IZ 908-0523 

robert.hornick@fitchratings.com 

Jill Schmidt 

+1 21Z 908·0644 

jiLl.schmidt@fitchratings.com 

2,780 

1,484 

413 

827 

3,363 

6,283 

9.7 

2.' 

2,816 

1,485 

430 

824 • 

3,234 

6,120 

10.0 

2.8 

Rating Rationale 

• Fitch lowered South Carolina Electric ft Gas Company's (SCEftG) ratings to their 

present level in June 2009, 

• The downgrade reflects the financial pressure from the company's plans to 

construct and finance two nuclear generating units for service in 2016 and 2019, 

respectively. SCEftG will own 55% of the two units at an estimated cost of 

$6,3 billion, 

• The downgrade also reflects the increase in business risk from the construction of a 

project of this size and complexity, and the substantial increase in debt and total 

capital over the extended construction period, The nuclear expenditures together 

with investments in its existing utility plant will more than double SCEftG's net 

plant investment and total capital by the end of the construction period_ 

The credit impact of the incremental debt burden is softened by legislation in South 

Carolina, the Base Load Review Act (BLRA), which permits utilities to recover 

capital costs, including a return on equity, during construction; and by sharing the 

construction costs with its joint owner Santee Cooper, a state-owned electric and 

water utility in South Carolina, 

• Other risk mitigants include an engineering procurement and construction (EPC) 

contract that fixes a portion of the plant cost and a financing plan that includes 50% 

equity financing. 

Key Rating Drivers 

• Maintaining budget and schedule for nuclear construction program will be critical to 

maintaining existing ratings. 

• Ratings will also be dependent on the timely receipt of annual rate adjustments to 

reflect nuclear-related construction work in progress in rate base. 

• The company's ability to secure non-nuclear rate adjustments is an important 

ratings factor, 

• Adherence to the financing plan of using a balanced mix of debt and equity to fund 

nuclear construction program is an important component of the ratings. 

Recent Events 

Nuclear Plant Progress 

On Feb, 11, 2009, the South Carolina Public Service Commission (PSC) approved 

SCEftG's combined application for a certificate of environmental compatibility and 

public convenience and necessity, and for a base load review order to construct and 

operate a two-unit 2,234-megawatt (MW) nuclear facility to be located at the site of 

the existing V_c. Summer Nuclear Station_ The PSC determined the capacity was 

needed and that SCEftG's decision to construct the plant was prudent and the capital 

costs were reasonable, The prudency finding is binding on all future commissions as 

www.fitchratings.com August 3, 2009


Exhibrt No. SCE-5(C) 

Corpo rates 

long as construction proceeds in accordance with the schedules, estimates and 

projections, including contingencies, set forth in the approved application. The 

combined application was filed under the BLRA, which requires the PSC to conduct a 

full pre· construction prudency review of the proposed units and of the EPC contract 

under which the units will be built. 

As part of the order, the PSCalso approved the initial rate increase of $7.8 million, or 

0.4%, to recover the cost of capital on nuclear project expenditures through 

June 30, 2008. The new rates became effective March 29, 2009. 

On May 29, 2009, SCE&G filed for an additional 1.1% rate increase under the BLRA to 

recover capital costs from July 1, 2008, through June 30, 2009. If approved, the new 

rates would become effective October 2009. Under the BLRA process, SCE&G is 

permitted to file each May to recover the cost of capital on its construction·work-inprogress 

(CWIP) balance as of the filing date, followed by a five-month review process, 

with new rates effective the following October. 

Fuel Cost Recovery 

On April 22, 2009, the PSC approved a settlement agreement between SCE&G, the 

Office of Regulatory Staff and others that provided for a three-year phase-in of 

SCE&G's uncollected fuel costs of about $110 million. 

City of Orangeburg 

On April 22, 2009, SCE&G agreed to continue to provide the City of Orangeburg, SC, 

with approximately 190 MW of wholesale electric power through 2010. The city 

extended its contract with SCE&Gafter the North Carolina PSCrejected a contract with 

Duke Energy Corporation (Duke) priced at Duke's average system cost rather than 

market. 

Liquidity and Debt Structure 

Liquidity for working capital 

purposes is provided by a $350 

million commercial paper program 

that is fully backed by a $400 million 

bank credit facility which expires in 

Dec. 2011. South Carolina Fuel Security 

Company, a direct subsidiary of FMB 

PC Bond 

SCANA, which acquires, owns and FMB 

provides financing for SCE&G's 

SCE&G Debt Maturity 

Coupon (%) 

6.7 

4.2 

7.125 

Schedule 

Amount 

Maturity 

($ Mil.)_~=D'".t•• 

150 2/1/11 

4 

1111/12 

150 6115/13 

Source: Company reports. 

nuclear and fossil fuels and emission 

allowances, maintains an additional 

$250 million bank credit facility that matures in December 2011. At March 31, 2009, 

short-term borrowings totaled $92 million compared to $34 million at year-end 2008, 

and cash and equivalents amounted to $218 million. There are no financial covenants in 

the credit agreement. 

Debt maturities are sufficiently laddered and should be manageable. Maturities through 

2013 are shown in the table above. Thereafter, the next debt maturities are in 2018 

and 2032. 

2 South Carolina Electric & Gas Company August 3, 2009



Corporates 

Financial Summary - South Carolina Electric & Gas CO. 

(S Mil., Fiscal Years Ended Dec.) 

LTM Ended 

3/09 200S 2007 2006 2005 2004 

Fundamental Ratios 

FFO/lnterest Expense (xl 2.3 3.4 4.S 5.1 4.9 4.3 

CFO/lnterest Expense (xl 3.3 3.5 4.5 4.2 3.8 4.6 

Debt/FFO (xl 14.3 8.0 4.3 3.9 4.1 4.9 

Operating EBIT !Interest Expense (xl 3.2 3.3 3.2 3.2 2.1 3.2 

Operating EBITDAllnterest Expense (x) 4.7 4.8 5.0 5.1 5.3 4.7 

Debt/Operating EBITOA (xl 4.1 3.9 3.2 3.2 3.0 3.4 

Common Dividend Payout (%) 77.3 61.7 60.1 

Internal Cash/CAPEX (%) 31.3 36.0 64.8 76.3 76.4 79.3 

(APEX/Depreciation (%) 290.9 278.9 222.1 143.0 71.0 198.6 

Profitability 

Adjusted Revenues 2,780 2,816 2,481 2,391 2,421 2,089 

Net Revenues 1,484 1,485 1,399 1,353 1,349 1,258 

Operating and Maintenance Expense 501 506 478 461 441 431 

Operating EBITDA 827 824 774 754 777 696 

Depreciation and Amortization Exp. 265 265 276 286 465 221 

Operating EBIT 562 559 498 468 312 475 

Gross Interest Expense 176 170 154 148 147 148 

Net Income for Common 269 266 238 227 251 225 

Oper. Maint. Exp. % of Net Revenues ll.8 34.1 34.2 34.1 32.7 34.3 

Operating EBIT % of Net Revenues 37.9 37.6 35.6 34.6 23.1 37.8 

Cash Flow 

Cash Flow from Operations 413 430 540 474 410 535 

Change in Working Capital 178 25 (49) (140) (169) 52 

Funds from Operations 235 405 589 614 579 483 

Dividends (172) (164) (143) (162) (158) (187) 

Capital Expenditures (771) (739) (613) (409) (llO) (439) 

Free Cash Row (530) (473) (216) (97) (78) (91 ) 

Net Other Investment Cash Flow (3) (20) 19 (22) (18) (19) 

Net Change in Debt 614 556 140 115 39 

Net Change in Equity 106 15 75 9 94 38 

Capital Structure 

Short-Term Debt 92 34 464 362 303 153 

Long-Term Debt 3,271 3,200 2,043 2,049 2,066 2,206 

Total Debt 3,363 3,234 2,507 2,411 2,369 2,359 

Total Hybrid Equity and Minority Interest 96 182 176 174 170 170 

Common Equity 2,824 2,704 2,622 2,457 2,362 2,164 

Total Capital 6,283 6,120 5,305 5,042 4,901 4,693 

Total Debt/Total Capital (%) 53.5 52.8 47.3 47.8 48.3 50.3 

Total Hybrid Equity and Minority Interest/Total Capital (X) 1.5 3.0 3.3 3.5 3.5 3.6 

Common Equity/Total Capital (%) 44.9 44.2 49.4 48.7 48.2 46.1 

Common Dividends PYd 

Note: Numbers may not add due to rounding. LTM - Latest 12 months. Operating EBIT - Operating income before total reported state and federal income tax expense. 

Operating EBITDA- Operating income before total reported state and federal income tax expense plus depreciation and amortization expense. 

Source: Company reports/Fitch Ratings. 

South Carolina Electric 8: Gas Company August 3, 2009 3



Corpo rates 

Copyright 002009 by Fitch, IIlC., Fitch Ratings ltd. and its subsidiaries. One State Street Plaza, NY, NY10004. 

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4 South Carolina Electric & Gas Company August 3, 2009






OF 

CHARLES A. WHITE 





BEFORE THE 


South Carolina Electric & Gas Company Docket No. ELI 0- -000 

DIRECT TESTIMONY AND SUPPORTING EXHIBIT OF 

CHARLES A_ WHITE 



Direct Testimony of Charles A. White 

Docket ERI 0-_-000 

Page I ofl7 


I. INTRODUCTION AND QUALIFICATIONS 

2 Q. 

PLEASE STATE YOUR NAME, TITLE AND BUSINESS ADDRESS. 

3 A. 

4 

5 

6 

My name is Charles A. White. I am Vice President - Electric Transmission for South 

Carolina Electric & Gas Company ("SCE&G" or the "Company"), on whose behalf! am 

testifying in this proceeding. My business address is 220 Operations Way, Cayce, South 

Carolina 29033. 

7 Q. 

BRIEFLY OUTLINE YOUR RESPONSIBILITIES AS VICE PRESIDENT - 

8 

ELECTRIC 

TRANSMISSION. 

9 A. 

10 

11 

I am responsible for transmission policy, local and regional transmission planning, ERO 

Compliance, and system operations for South Carolina Electric & Gas Company's 

transmission system as well as interconnected transmission system operations. 

12 Q. 

PLEASE DESCRIBE YOUR EDUCATIONAL AND BUSINESS BACKGROUND. 

13 A. 

14 

15 

16 

17 

18 

19 

20 

21 

[ hold a Bachelor of Science degree in Electrical Engineering and a Masters of Business 

Administration from the University of South Carolina. [am a registered Professional 

Engineer in the State of South Carolina and have over 44 years experience in various 

areas of the electric utility industry. I have been active in many industry organizations 

including the Electric Power Research Institute (EPRl), the Edison Electric Institute, the 

Institute of Electrical and Electronics Engineers (IEEE), the SERC Reliability 

Corporation, the Southeastern Electric Reliability Council and VACAR. I am the 

immediate past chairman of the SERC Reliability Corporation and serve on the SERC 

Board Executive Committee and the SERC Board HR and Compensation Committees. I




Page 2 ofl7 


have served as Chairman of VA CAR and currently serve as a subject area advisor for 

2 

3 

4 

5 

EPRI in the areas of Grid Operations and Planning, the System Reliability Initiative, and 

Emergency Disaster and Mitigation Planning. I am a Lifetime Senior Member ofIEEE 

and am past chairman of the IEEE Insulated Conductors committee, IEEE Special 

Technical Conference and IEEE T&D Conference and Exposition Committee. 

6 Q. 

7 

HAVE YOU PROVIDED TESTIMONY PREVIOUSLY IN REGULATORY 

PROCEEDINGS? 

8 A. 

9 

Yes, I have testified before the Public Service Commission of South Carolina 

("SCPSC"). 

10 II. 

TESTIMONY PURPOSE AND SUMMARY 

II Q. 

WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? 

12 A. 

13 

14 

15 

16 

SCE&G is requesting recovery of the costs it incurred during its attempt to form a 

regional transmission organization ("RTO"). The purpose of my testimony is to describe 

the activities undertaken by SCE&G in the attempt to form an RTO in response to the 

FERC's orders and initiatives. SCE&G incurred significant costs in connection with 

those activities, and I describe the types of costs that were incurred. 

17 Q. 

PLEASE SUMMARIZE YOUR TESTIMONY. 

18 A. 

19 

20 

I describe the efforts of SCE&G, Duke Power and Progress Energy Carolinas (formerly 

Carolina Power & Light or CP&L) to form GridSouth as a southeastern RTO. I discuss 

the FERC's granting GridSouth provisional RTO status and later ordering mediation




Page 3 of17 


among all transmission-owning southeastern utilities in an attempt to form one 

2 

3 

4 

5 

southeastern RTO. I describe the costs GridSouth incurred during its formation and as it 

was being developed to be a fully operational RTO before the deadline mandated by 

Order No. 2000. Finally, I describe the steps taken after mid 2002 to mitigate 

GridSouth's total expenditures and to terminate the GridSouth RTO. 

6 III. GRID SOUTH FORMATION 

7 Q. 

DESCRIBE THE EVENTS LEADING TO THE FORMATION OF GRID SOUTH. 

8 A. 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

SCE&G had been discussing the formation of an ISO or an independent RTO with 

various transmission owners in the southeast since 1997. In December 1999 the FERC 

issued Order No. 2000 requiring all transmission-owning utilities that were not 

participating in an RTO to submit to the FERC by October 15,2000, either (I) a proposal 

to participate in an RTO that would be operational no later than December 15,2001, or 

(2) an alternative filing describing efforts to participate in an RTO, obstacles to RTO 

participation, and any plans and timetable for future efforts. According to Order No. 

2000, utilities could file an RTO proposal by means of a petition for a declaratory order 

asking the FERC whether a proposed transmission entity that would be operational by 

December 15,2001, would quality as an RTO. The petition was required to contain a 

description of the organization and operational structure, a list of the intended 

participants of the organization, an explanation of how the organization would satisfy 

each of the RTO minimum characteristics and functions, and a commitment to submit 

necessary FPA section 203, 205 and 206 filings promptly after receiving the 

Commission's determination on the declaratory order petition.




Page 4 of 17 


Following the issuance of Order No. 2000, SCE&G worked collaboratively with Duke 

2 

3 

Power and Carolina Power & Light to develop an RTO known as GridSouth. 

2000, the three companies (the "GridSouth Sponsors") reached agreement on 

By spring 

4 

5 

6 

7 

GridSouth's basic business structure, set up a management committee and began 

developing a business plan. When the parties formally agreed to pursue the GridSouth 

Project, they began drafting the documents that would be filed at the FERC. During 

summer 2000, the GridSouth Sponsors met with the FERC commissioners and FERC 

8 

staff to discuss plans for GridSouth. 

By August 2000, Duke, CP&L and SCE&G had 

9 

developed a preliminary draft "strawman" document covering the major areas of 

10 

GridSouth operations. 

The strawman document was posted on an internet webpage for 

II 

12 

13 

14 

15 

stakeholder comment and input. Starting in August 2000 five stakeholder meetings were 

held in Charlotte and Raleigh, North Carolina and in Columbia, South Carolina. In 

addition to the formal stakeholder meetings, there were numerous individual meetings 

with stakeholders and responses to stakeholder questions and comments via email and 

telephone conversations. 

16 

17 

18 

On October 16, 2000, the GridSouth Sponsors filed with the FERC a petition for a 

declaratory order requesting authorization and approval to establish GridSouth Transco, 

LLC as an RTO. 

19 Q. 

DID THE FERC GRANT GRIDSOUTH RTO STATUS? 

20 A. 

21 

22 

Yes. On March 14,2001, the FERC granted GridSouth provisional RTO status, finding 

that the GridSouth proposal by SCE&G, Duke and CP&L "reflects a realistic and 

balanced effort to create an RTO in the Southeast region." The FERC's March 14th



Docket ERIO-~-OOO 

Page 5 of 17 

Exhibit 

No. SCE-6 

Order directed the GridSouth Sponsors (I) to re-file certain documents with limited 

2 changes as reflected in the Order; (2) to meet with representatives of the South Carolina 

3 Public Service Authority ("Santee Cooper") to attempt to reach agreement on Santee 

4 Cooper's participation in the GridSouth RTO; and (3) to have discussions with other 

5 transmission owners in the southeast to explore expansion ofGridSouth's geographic 

6 scope. In accordance with FERC's March 14th Order, the GridSouth Sponsors 

7 commenced extensive discussions with Santee Cooper and other transmission owners in 

8 the southeast. The meetings with Santee Cooper over the next three months were 

9 numerous and very comprehensive. The GridSouth Sponsors also had discussions with 

10 Southern Company, Georgia Transmission Corporation, Southeastern Power 

11 Administration and Tennessee Valley Authority. 

12 On May 14, 2001, GridSouth made a compliance filing with the FERC as required by the 

13 FERC's March 14th order. The filing contained revisions to the OATT, Operating 

14 Agreement and LLC Agreement addressing the specific issues identified in the FERC's 

15 March 14th order and a status report on GridSouth' s efforts to expand its scope in the 

16 southeast region. In addition, GridSouth' s Generator Interconnection Procedures, 

17 congestion management procedures, a Reliability Operating Agreement between 

18 GridSouth and each of Duke, CP&L and SCE&G, and Master Definition List were filed 

19 with the FERC. 

20 On July 12,2001, the FERC issued two orders affecting GridSouth. In one of the orders, 

21 which addressed GridSouth's compliance filing, the Commission recognized "the 

22 considerable efforts of Applicants to meet with other transmission owners in the region.


Direct Testimony ofChar]es 


Page 6ofI7 

A. White 


We understand that the two-month window, from the issuance ofthe March 14 order to 

2 

3 

4 

5 

6 

the May 14 reporting deadline, was a relatively short period of time for Applicants to 

enter into final agreements with other transmission owners. Nor do we find fault with 

Applicants where other transmission owners have chosen to take other approaches to 

RTO formation rather than pursuing membership in GridSouth. However, we are 

disappointed by the lack of progress Applicants have made in expanding the RTO's 

7 

scope through the inclusion of additional members in GridSouth." 

At the same time, the 

8 

9 

10 

II 

12 

Commission significantly shifted direction in its RTO formation strategy and issued a 

second separate, concurrent order directing the GridSouth Sponsors, as well as all the 

parties in four other FERC proceedings involving Southern, the Southwest Power Pool, 

Entergy, Florida Power & Light, Florida Power Corporation and Tampa Electric 

Company "to participate in settlement discussions for 45 days before a mediator and 

13 

appropriate consultants to assist and provide advice during the mediation." 

Mediation 

14 

15 

16 

17 

18 

19 

was ordered at this point because, notwithstanding its earlier order granting provisional 

RTO status to GridSouth, the FERC decided that all federal jurisdictional transmission 

owners in the Southeastern U.S. should combine to form a single RTO. This mediation, 

contemplating a merger ofthe GridSouth efforts with the RTO efforts of other Southeast 

region utilities, did not supersede the work being done on GridSouth, but rather 

proceeded on a parallel path. 

20 Q. 

WHAT WAS THE RESULT OF THE MEDIATION? 

21 A. 

22 

The mediation took place for 45 days during July and August 2001 and included 

approximately 200 participants from the parties in the various FERC proceedings, State




Page7of17 


Commissions in the southeast, TVA, Santee Cooper, SEPA, as well as diverse 

2 

3 

4 

5 

6 

7 

stakeholder interests throughout the Southeast RTO footprint. At the conclusion of the 

mediation process, the mediator submitted her 136-page Mediation Report 

recommending that the FERC consider adopting an RTO model called the "Collaborative 

Governance Model." This model was the convergence and evolution of some of the best 

aspects of the GridFlorida, GridSouth and Entergy models, and was described in detail by 

the mediator and presented as a fully integrated proposal for the Commission's 

8 

consideration. 

After the mediation, the GridSouth Sponsors developed a new governance 

9 

structure to respond to stakeholder concerns regarding the "Transco model" that were 

10 

expressed during the mediation. 

This revised proposal was circulated to the stakeholders 

II 

12 

13 

for comment in conjunction with a stakeholder meeting in May 2002. The revised 

proposal was to be submitted to the North Carolina and South Carolina commissions in 

June 2002 for their approval. 

14 Q. 

WAS THE COLLABARATIVE GOVERNANCE MODEL ADOPTED? 

15 A. 

16 

17 

18 

19 

No. In October 2001, the FERC sought more input on RTO issues in general by holding 

a public conference on RTO issues. At the conclusion of the public conference, the 

FERC issued an order establishing Docket No. RMOI-12-000 on Electricity Market 

Design and Structure (Standard Market Design). The FERC's order terminating the 

mediation proceedings was not issued until December 2004.



Docket ERI O-~-OOO 

Page 8 ofl7 


I Q. 

DID GRIDSOUTH EVER BECOME OPERATIONAL? 

2 A. 

3 

4 

5 

6 

7 

8 

9 

10 

II 

12 

13 

14 

IS 

16 

17 

No. In November 2001, the FERC announced the establishment of state-federal regional 

panels to address RTO and seams issues and reflect state interests affected by RTO 

developments following the issuance of Order No. 2000. The panels convened during the 

winter and early spring 2002 and preceded the issuance of the FERC's standard market 

design NOPR in July 2002. During summer 2002, the Southeastern state commissions 

announced that they would undertake an analysis of the costs and benefits of forming 

three RTOs (including GridSouth) in the Southeast (SEARUC Study). In light of the 

SMD NOPR issuance and the announcement of the SEARUC Study, the GridSouth 

Sponsors decided to postpone filing applications with their respective state commissions 

for approval of the transfer of operational control of their transmission systems to 

GridSouth. The Sponsors also decided to take steps to mitigate the costs of continuing 

operations associated with the GridSouth implementation project. However, the 

Sponsors tried to balance their cost mitigation efforts with efforts to preserve the progress 

on implementing GridSouth that had been achieved to that point so that there would be a 

cost effective and orderly means by which to restart GridSouth when and if all regulatory 

approvals were obtained. 

18 

19 

20 

21 

22 

The SEARUC Study was issued November 6, 2002 and the FERC issued a "White 

Paper" subsequent to the SMD NOPR in April 2003. The GridSouth Sponsors filed 

comments in the SMD NOPR, White Paper, and the SEARUC Study as well as provided 

technical data and assistance to the consultants who prepared the SEARUC Study. The 

GridSouth Sponsors discussed the issues presented in all three documents with state




Page90f17 


regulators and attended various technical conferences sponsored by the FERC. The 

2 GridSouth Sponsors continued to monitor RTO developments in the southeast and other 

3 regions, the SMD rulemaking and related proceedings, and proposed national energy 

4 legislation. 

5 From June 2002 through mid-2003, regulatory and legislative uncertainty surrounding the 

6 establishment of a single Southeastern RTO continued to grow. Consequently, during 

7 this period the GridSouth Sponsors terminated all vendor and services contracts, released 

8 all GridSouth employees and sold the building that would have housed GridSouth's 

9 headquarters. On August II, 2005, the GridSouth Sponsors notified the FERC that they 

10 were terminating the GridSouth project, and the FERC officially terminated the 

II proceeding in Docket No. RTOI-74-000 by order issued October 20,2005. 

12 Q. WHAT DOES SCE&G SEEK IN THIS CASE? 

13 A. This is the first transmission rate case that SCE&G has filed since the termination of the 

14 GridSouth proceeding; therefore, SCE&G is now requesting amortization of the costs that 

15 SCE&G has incurred in good faith in response to the Commission's RTO initiative. 

16 Q. WHEN DID SCE&G BEGIN ACCUMULATING COSTS ASSOCIATED WITH 

17 THE FORMATION OF GRIDSOUTH? 

18 A. SCE&G began accumulating costs associated with the formation of GridSouth on May 

19 15, 2000, the date the GridSouth Limited Liability Agreement was signed by Duke, 

20 CP&L and SCE&G. During the early phases of GridSouth's formation, substantial 

21 management, personnel and other company resources were required, and legal and




Page 10 of 17 


outside consultants' fees were incurred in connection with stakeholders meetings and 

2 drafting corporate governance documents, regulatory filings and the documents required 

3 for the October 2000 petition for declaratory order. For example, the October 2000 filing 

4 alone included the Limited Liability Agreement that created the governance structure for 

5 GridSouth sufficient to satisfY the independence requirement of Order No. 2000; the 

6 Transmission Operating Agreement that defined Functional Control and set out the 

7 contractual arrangement under which each participant transferred to GridSouth control of 

8 their transmission facilities and set out the general operational relationship between the 

9 GridSouth entity and each of Duke, CP&L and SCE&G; the Market Monitoring Protocol; 

10 the Operations Protocol that addressed congestion management, parallel path flows, 

II ancillary and energy imbalance services and detennined the methodology for A TC 

12 calculations; the Planning Protocol; and GridSouth's OATT that included a detailed 

13 description of the rates, rate designs used, a proposal for calculating service rates and 

14 charges as well as the GridSouth Transmission Service Charge fonnula rate; and the 

15 testimony of several expert witnesses. 

16 On November 3, 2000, the three GridSouth Sponsors filed a petition for declaratory order 

17 with the FERC seeking approval of their proposed accounting treatment for start-up costs 

18 and stated that they anticipated spending over $100 million in start-up costs for the period 

19 May IS, 2000 to December IS, 200 I. The FERC granted that petition and accepted the 

20 proposed accounting treatment for start-up costs in an order issued January 25, 200 I. In 

21 that order, the FERC said that the start-up costs could be accounted for as deferred debits, 

22 subject to the accrual of carrying charges and subject to recovery in a future rate case 

23 such as this one. The Commission made it clear that the GridSouth Sponsors might seek



Docket ER1 0- -000 

Page 11 of17 


rate recovery in the future for the deferred debits, but would have to show at that time 

2 

that the costs were reasonably 

incurred. 

3 Q. 

4 

PLEASE DESCRIBE THE GRIDSOUTH COSTS THAT SCE&G SEEKS TO 

RECOVER. 

5 A. 

6 

7 

8 

9 

10 

11 

SCE&G's expenditure for GridSouth is $13,566,274 plus carrying charges of$I,596,251. 

This represents SCE&G's 17% share of the total costs the GridSouth Sponsors incurred 

forming the GridSouth RTO and trying to develop it as a fully operational RTO by the 

December 15,2001 deadline mandated by the Commission's Order No. 2000. GridSouth 

began accumulating costs on May 15,2000, in accordance with the Commission's 

January 25, 2001 accounting order; SCE&G's total costs of$15,162,525 million are its 

GridSouth expenditures and carrying costs through December 31, 2003. 

12 Q. 

PLEASE DESCRIBE THE GRID SOUTH EXPENDITURES. 

13 A. 

14 

15 

16 

17 

18 

19 

20 

Under the GridSouth Limited Liability Agreement, SCE&G was responsible for 17% of 

all GridSouth costs. GridSouth used the funds contributed by the GridSouth Sponsors 

(including SCE&G) for the many projects required for a fully operational RTO. Initially, 

these costs included legal fees, consulting fees, labor costs, travel, housing and other 

business expenses as the GridSouth Sponsors conceived, sought authorization for and 

developed the GridSouth RTO. Outside counsel and consultants provided extensive 

services and worked closely with employees of the GridSouth Sponsors during every step 

ofthe process. Some of the areas in which the outside counsel and consultants were 

21 

involved 

were:




Page 12 ofl7 


(i) Analyzing Order No. 2000 and conceiving, developing and designing the 

2 GridSouth Transco; 

3 (ii) Meeting with and coordinating with the other GridSouth Sponsors, and eventually 

4 obtaining a consensus on the transco model; 

5 (iii) Negotiating how the GridSouth RTO would operate, how it would relate to the 

6 GridSouth Sponsors and transmission owners, and how it would satisfy the requirements 

7 of Order No. 2000; 

8 (iv) Preparing "strawman" documents regarding GridSouth operations to share with 

9 stakeholders; 

10 (v) Negotiating with stakeholders concerning GridSouth, including five separate 

11 stakeholder meetings prior to the original GridSouth filing; 

12 (vi) Coordinating with GridSouth Sponsors to prepare the GridSouth filings, including 

13 (a) the original GridSouth proposal filed in October 2000 in response to Order 2000 

14 (which contained, inter alia, the GridSouth OATT, the GridSouth LLC agreement, the 

15 Transmission Operating Agreement between GridSouth and the transmission owners), 

16 and (b) the petition to address the accounting for GridSouth expenses; 

17 (vii) Preparing responses to the interventions and comments filed in response to the 

18 GridSouth proposal; 

19 (viii) Designing a formula rate for GridSouth;




Page 13 of 17 


(ix) Analyzing and responding to the Commission orders conditionally accepting 

2 GridSouth as an RTO and directing further filings; 

3 (x) Negotiating with Santee Cooper on the latter's participation in GridSouth; 

4 (xi) Participating in the extensive Southeastern RTO regional mediation directed by 

5 the Commission in the summer of 200 I ; 

6 (xii) Participating in further stakeholder processes after the conclusion of the 

7 Commission directed Southeastern mediation; and 

8 (xiii) Analyzing the Commission's SMD initiatives and participating in the SEARUC 

9 RTO cost-benefit study. 

10 At every stage of the process - from the initial negotiations, to the termination of 

II GridSouth in 2005 - the labor, legal and consulting expenses included extensive legal 

12 research and both legal and policy analysis of the issues raised by Order No. 2000, by the 

13 creation of the GridSouth Transco, and by the various Commission orders issued 

14 throughout this period. Moreover, these activities always faced the additional complexity 

15 of negotiating and reaching consensus with the other GridSouth Sponsors and addressing 

16 many stakeholder issues. 

17 The GridSouth Sponsors engaged outside consultants to assist in the development of the 

18 GridSouth RTO and preparation of the necessary documents. 

19 Once the initial compliance filing was made, GridSouth commenced the more complex 

20 and costly task of creating, by the December 15, 2001 deadline imposed by Order No.



Docket ER I0- -000 

Page 140fl7 


2000, a fully functional RTO. The major projects that were key to insuring GridSouth's 

2 

3 

4 

5 

6 

7 

8 

operational viability included (i) commercial operations and customer interface; (ii) 

system operations and planning; (iii) information technology; (iv) human resources and 

recruiting; and (v) operation facilities. GridSouth entered into many contracts with 

vendors to supply the computer hardware and software for these programs and to assist 

with recruiting and staffing. GridSouth entered into a contract with a leasing and 

construction company for that company to purchase land and construct a building at Fort 

Mill South Carolina that would serve as the GridSouth headquarters and control center. 

9 

10 

11 

By mid 2002, with the preparation of the cost benefit study for the southeastern state 

commissions and the Commission's rulemaking on standard market design, the 

GridSouth Sponsors decided to suspend their efforts toward creating a fully functional 

12 

RTO pending further clarification of the regulatory requirements. 

Over the next twelve 

13 

14 

months, all GridSouth employees were terminated as were all vendor contracts. 

appeared unlikely that GridSouth would ever become operational, the GridSouth 

Once it 

15 

16 

17 

Sponsors mitigated the facilities expense by selling the assets (the land and building) 

associated with the facilities project- Exhibit SCE-7 itemizes GridSouth's expenditures 

by month from January 200 I through December 31, 2003. 

18 Q. 

WERE GRIDSOUTH'S EXPENSES REASONABLE AND PRUDENT? 

19 A. 

20 

21 

22 

Yes. 1have already described the effort required to develop the initial and compliance 

filings with the FERC and the participation in the Southeastern RTO regional mediation. 

The effort to develop the computer software and the facilities to operate GridSouth began 

in late October/early November 2000. It was necessary to start at that time in order for



Docket ERI 0-_-000 

Page 15 of 17 


GridSouth to have a reasonable chance of completion within the December 15,2001 time 

2 frame required by Order No. 2000. SCE&G, through GridSouth's Management 

3 Committee, carefully evaluated every aspect of the project in an attempt to control cost. 

4 Each of the many decisions made during the course of the project was made with an eye 

5 toward reducing costs to customers in the long term. Some of the principal cost control 

6 decisions were: 

7 (i) Selecting software solutions that were both industry standard solutions and ones 

8 that had been tested and proven by prior application; 

9 (ii) Selecting system operations software that was compatible with the system control 

IO software and information systems in use in the GridSouth member utilities; 

II (iii) Integrating meter information and data flows from the existing utility control 

12 centers into the system operations computer system rather than reproducing metering and 

13 information flows independently; 

14 (iv) Deferring any decision concerning implementation of real time balancing and 

15 congestion management until the need for such mechanisms could be cost justified; 

16 (v) Using utility personnel to displace higher cost resources from outside contractors 

17 for the implementation of project and related tasks; 

18 (vi) Negotiating substantial economic development incentives for locating the 

19 headquarters facility in South Carolina;




Page 160fl7 


(vii) 

Establishing and maintaining staffing levels appropriate for each stage of the 

2 

development of the RTO; and 

3 

(viii) 

Negotiating contracts with terms that included clear deliverables, milestones and 

4 

penalties for non-performance. 

5 

6 

The GridSouth project proceeded within budget and successfully maintained an 

aggressive time line. Had regulatory policy remained supportive, GridSouth was on target 

7 

to begin operations as a fully functional RTO on April!, 

2002. When the FERC's 

8 

9 

10 

II 

12 

policies changed in the summer of 200 I, the management team prudently scaled back 

operations to allow completion of committed and ongoing software and other 

development projects while minimizing costs and keeping options open. And, as I have 

previously stated, once it appeared unlikely that GridSouth would commence operations, 

the facility was sold to further mitigate expenses_ 

13 

14 

15 

16 

All of GridSouth's expenses were in response to the Commission's directions and 

guidance. Moreover, the Public Service Commission of South Carolina has approved the 

recovery of GridSouth expenses in retail rates. The Commission, having directed the 

activities which led to these expenditures, should do the same. 

17 Q. 

18 

PLEASE DESCRIBE METHODOLOGY FOR CALCULATING AND 

RECOVERING THE PROPOSED CHARGES. 

19 A. 

20 

21 

The methodology for calculating and recovering the proposed amortization of SCE&G's 

GridSouth RTO cost based on the GridSouth costs that I discuss in my testimony is 

described in the testimony of SCE&G witness Alan C. Heinz.



Docket ER10-_-000 

Page 170f17 


Q. DOES THIS CONCLUDE YOUR TESTIMONY? 

2 A. Yes.


AFFIDAVIT 

COUNTY OF LEXINGTON 

STATE OF SOUTH CAROLINA 

) 

) 

) 

Charles White, being duly sworn, deposes and states tbat tbe attached are his sworn 

testimony and exhibits, and tbat tbe statements contained tberein are true and correct to tbe best 

of his knowledge, infonnation and belief. 

c~ 


tbis 22 nd day of December, 2009 

My Commission Expires: r? I 'bO (:LO \1-



DOCKET ER10- -000 

EXHIBIT 

NO. SCE-7 

GRID SOUTH EXPENDITURES 

FROM 

JANUARY 2001 THROUGH DECEMBER 2003

......... " ..... r ....................... "'11 

Exhibit No. seE- 7 

Page 1 of 3 

Jan '01 Feb '01 Mar '01 Apr '01 

May '01 

Jun '01 Jul'01 Aug '01 

I 

Sep '01 I 

Oct '01 Nov '01 Dec '01 2001 

Month Month Month Month Month Month Month Month Month Month Month Month YTO 

Project LIne Actual I Actual I Actual I Actual I Actual Actual I Actual I Actual I Actual Actual I Actual I Actual Total 

System Operations & Planning 

• 

478,420 

• 

228,775 

• 

251,187 

• 

540,808 

• 

131,424 

• 

781,689 $ 694,988 $ 2,726,073 

• 

164,911 

• 

272,897 

• 1,353,787 • 

2,218,629 $ 9,839,348 

Commercia' Ops & Customer Interface 427,376 371,411 845,151 1,686,343 704,137 1,987,323 1,813,816 1,347,708 886,211 384,177 87,721 215,647 10,536,019 

Corporate Services Project 486,106 86,183 (7,920) 34,710 24,214 547,759 147,274 180,337 110,495 231,238 101,519 96,765 2,037,681 

Information Technology project 258,350 12,887 84,323 119,927 336,084 355,186 551,257 534,783 6,111,441 409,334 221,991 583,945 9,679,509 

HR & Recruiting 1,264,402 431,369 97,381 88,046 81,500 244,948 220,223 218,013 67,785 189,831 155,911 191,391 3,250,799 

Filcilities Project 67,891 58,885 61,498 201,385 275,362 489,049 802,489 901,620 114,642 1,542,827 767,741 613,746 5,698,932 

Customer Readiness 83,202 57,376 90,168 8,280 120,625 - 369,560 

Integretlon, SImulation & Transition 34,190 78,374 (8,433) 104,150 - 121,000 53,435 69,520 49,nO 25,280 527,286 

Program Management 883,964 376,028 142,472 305,596 125,079 240,046 296,437 222,526 188,513 181,070 136,016 113,767 3,211,515 

"o 

o 

'" .... 

"W 

.... 

I 

o 

W 

-J 

;:J 

~ 

:g 

'" 

~ 

~ 

~. 

n 

~. 

~ 

.... 

.... 

-.... " 

" 

-.... 

'" 

"o 

o 

'" 

Other Progrilm Costs 362,924 183,173 216,022 276,538 302,279 134,175 295,371 355,301 153,805 434,250 218,289 1,298,358 4,240,486 

Total program costs 4,227,434 1,781,900 1,851,668 3,301,295 2,070,248 4,892,605 4,742,381 6,607,360 7,641,238 3,714,744 3,092,725 5,355,526 49,279,125 

Project General Support Costs from TOs 3,685,051 387,837 389,400 195,526 965,593 1,189,686 72,994 626,117 528,033 487,713 658,984 718,474 9,875,410 

Genera' support costs from Transmission Owners 3,685,051 387,837 389,400 195.526 944,660 621.794 (117.057) 361,033 226,810 163.230 287,105 334.202 7.479.592 

'nterface costs 10,933 10,451 13.974 8,179 2,508 3,947 169 50.161 

Carrying charges 67.090 47,240 58.893 72,149 158,982 133.087 176,077 256.904 298.715 320,537 371,710 364.272 2.345.656 

Total GridSouth project costs $ 7,912,486 $ 2,169,738 $ 2,241,068 $ 3,496,821 $ 3,025,841 $ 6,062,292 $ 4,815,375 $ 7,233,477 $ 8,169,271 $ 4,202,457 

• 3,751,709 • 

6,074,000 $ 59,154,535 

POlO 1

"0 

0 

'" .... 

"w 

Exhibit No. seE- 7 

.... 

I 

Page 2 of 3 0 

0W-J 

'" 

Dec '02 "'02 

Month 

YTO 

Project Line [ Actual [ Actual Actual [ Actual [ Actual [ Actual [ Actual Actual Actual Actual [ Actual [ Actual Total 

'" 

to 

'" 

System Operations & Planning S 1,867,468 $ 91,011 $ 31,021 $ 30,267 $ $ $ $ $ $ 2,019,767 

• • • 2 

Commercial Ops & Customer Interface 274,916 267,126 271,976 261,679 211,229 210,096 120,000 120,000 1,737,020 

= 0 

'" n 

GndSouth Project Accounting 

----- ~ 

Corporate Services Project 149,976 82,024 172,014 80,704 51,884 37,683 15,9&8 3,388 11,898 605,538 

~. 

~. 

Infonnallon Technology project 222,662 198,520 207,093 230,7&6 132,110 104,390 112,605 75,089 10,457 (75,529) 1,218,153 ~ .... 

HR & Recruiting 85,007 56,550 49,996 38,614 9,545 74,678 25,192 4,795 "0 (24,592) 320,036 

.... 

" 

Facilities Project 669,910 606,904 259,315 256,212 262,292 193,696 172,031 140,643 33,333 (39,935) 143,331 88,876 2,788,608 -.... 

" 

Customer Readiness -.... '" 

" 

._--- 0 

Integration, Simulation & Transition 0 

'" 

Program Management 175,403 95,035 39,773 48,621 21,588 21,080 401,499 

Other Program Costs 286,059 189,460 167,793 168,736 567,229 (63,536) 377,110 4,010,916 1,826,599 46,070 (13,818) (4,231) 7,558,385 

Total program costs 3,731,399 1,588,630 1,198,979 1,115,589 1,255,877 578,086 822,907 4,346,648 1,859,932 24,775 129,763 (3,579) 16,649,005 

Project General Support Costs from TO. 363,747 525,631 813,311 632,159 762,925 678,505 855,104 765,246 804,507 360,548 568,982 1,065,570 7,986,233 

General support costs from Transmission Owners (16,916) 57,834 140,480 159,589 273,007 213,142 367,305 243,202 264,481 (212,313) 22,154 447,438 1,959,403 

Interface 

costs 

Carrying charges 380,663 467,796 472.831 472,570 489,917 465,363 487,798 512,044 540,026 572,861 546.828 618,132 6,026,830 

Total GrldSouth project costs $ 4,095,146 $ 2,114,261 $ 1,812,289 $ 1,747,748 $ 2,018,802 $ 1,256,591 $ 1,678,011 $ 5,101,894 $ 2,664,438 $ 385,323 $ 698,745 $ 1,061,991 $ 24,635,238 

Pag@ ~

"0 

0 

'" .... 

Exhibit No. seE· 7 

.... 

I 

Page 3 of 3 0 

0 

W 

-J 

"w 

SCANA's 

GridSouth Project Accountll!9 Amount of GridSouth 

~ 

Jan '03 Feb '03 Mar '03 Apr to Dec '03 2003 Cumulative Cumulative 

Month Month Month Month!s) YTD '" 

Project Project to 

Project Line Actual 

I 

Actual Actual Actual Total Total Total 

'" 

System operations & Planning S 11,859,115 1,692,129 

• • • • • • 2 

Commercial Ops & Customer Interface 12,273,039 1,751,190 

= 0 

Corporate Services Project 4,219 '96 

, 

4,416 2,647,634 377,780 

'" n 

~. 

~. 

Information Technology Project (3,306,161) (3,306,161) 7,491,501 1,068,932 

~ .... 

HR & Recruiting 3,570,835 509,508 

.... 

" 

Facilities Project 142,746 109,418 5,043,848 5,296,012 13,781,562 1,966,434 

-.... 

Customer Readiness 359,550 51,303 

-.... 

"0 

Integration, Simulation & Transition 527,286 75,236 0 

'" 

Program Management 3,613,014 515,'i26 

Other Program Costs (223,186) 3,569,990 152,234 108,418 3,607,457 15,406,327 2,198,267 

'" 

" 

'" 

Total program costs (76,221) 373,444 162,234 5,152,267 5,601,723 71,529,853 10,206,306 

Project General Support Costs from TOe 549,166 582,945 567,180 2,348,170 4,027,451 21,889,104 4,965,219 

General support costs from Transmission Owners (485) 4,737 10' 82,641 86,995 9,525,990 3,325,728 

Interface costs 50,161 34,240 

Carrying chargeS 549,650 558,207 567,080 2,265,529 3,940,466 12,312,953 1,596,251 

Total GrldSouth project costs 

• 

472,944 

• 

936,388 

• 

719,415 

• 

7,500,436 $ 9,629,184 $ 93,418,956 

• 

15,162,525 

Po,.l



DOCKET 

EXHIBIT 

ERIO-_-OOO 

NO. SCE-8 


OF 

ALAN C. HEINTZ 





BEFORE THE 


South Carolina Electric & Gas Company Docket No. ERIO- -000 





Direct Testimony of Alan C. Heintz 


Page I of28 


I 

I. INTRODUCTION 

2 Q. 

PLEASE STATE YOUR NAME, BUSINESS ADDRESS AND POSITION. 

3 A. 

My name is Alan C. Heintz. 

My business address is Brown, Williams, Moorhead & 

4 

5 

Quinn, Inc., ("BWMQ"), 1155 Fifteenth Street, NW, Suite 400, Washington, DC 20005. 

I am a Vice President ofBWMQ. 

6 Q. 

ON WHOSE BEHALF ARE YOU TESTIFYING? 

7 A. 

I am testifying on behalf of South Carolina Electric & Gas Company ("SCE&G"). 

8 Q. 

WHAT ARE YOUR DUTIES IN YOUR CURRENT 

POSITION? 

9 A. 

10 

II 

12 

13 

I provide consulting services on matters relating to power sales, transmission, and 

ancillary service issues associated with the Federal Energy Regulatory Commission's 

("FERC" or "Commission") open access transmission service and FERC's Order Nos. 

888, 889, 2000 and 679. I have provided consulting services to numerous Independent 

System Operators ("ISO") and Regional Transmission Organizations ("RTO"), including 

14 

the transmission owners of Midwest Independent Transmission 

System Operator, Inc. 

15 

16 

17 

("MISO"), DesertSTAR, to such entities as American Transmission Company, LLC, 

Trans-Elect, Inc., and to participants in other ISOs and RTOs - Alliance, GridFlorida, 

New York ISO, SeTrans ISA, ISO New England Inc., and California ISO. 

18 Q. 

PLEASE DESCRIBE YOUR PROFESSIONAL EXPERIENCE. 

19 A. 

20 

I was employed by the FERC from November 1985 to February 1995. I served as a 

Public Utilities Specialist in the [Electric 1 Rate Filings Branch from November 1985 to



Docket ER10- -000 

Page 2 of28 


1 October 1989. In November 1989, I was promoted to Section Chief in the Division of 

2 [Electric 1 Applications, and was responsible for supervising the review of the terms, 

3 conditions, and rates of electric rate applications for such services as interchange power, 

4 requirements power, and transmission. During my tenure with the FERC, I prepared or 

5 supervised the preparation of memoranda recommending acceptance, rejection, 

6 deficiency, or investigation in hundreds of cases. These included cases that set important 

7 precedents on electric transmission pricing, such as the merger compliance transmission 

8 tariffs for Northeast Utilities, the first generation of open access transmission tariffs 

9 ("OA TT") filed by utilities such as Entergy Services, Louisville Gas & Electric 

10 Company, Florida Power & Light Company, Kansas City Power & Light Company, and 

II American Electric Power Company, and the Pennsylvania Electric Company case 

12 involving Penntech Papers, Inc. I also taught a one-year course to FERC Staff and gave 

13 several presentations to the Edison Electric Institute Interconnection and Interchange 

14 Arrangements Committee on the pricing of power and transmission services. 

15 From February 1995 through October 2000, I was a Vice President of Stone & Webster 

16 Management Consultants, Inc. In this position, I provided consulting services to 

17 numerous electric utilities on matters involving requirements and off-system power rates, 

18 and rate and implementation strategies for developing OA TT filings, and organizing ISOs 

19 and RTOs. I also assisted several utilities in preparing their retail delivery services 

20 filings. I joined R.I. Rudden Associates, Inc. in November 2000 as a Vice President, 

21 where I continued providing consulting services to the electric industry. I joined BWMQ 

22 in February 2004.




Page 3 of28 


Q. 

PLEASE SUMMARIZE YOUR OTHER EXPERIENCE TESTIFYING BEFORE 

2 

REGULATORY BODIES AND COURTS ON UTILITY-RELATED MATTERS. 

3 A. 

4 

5 

6 

During my tenure at the FERC, I was assigned to the Commission's advisory staff and, 

therefore, was precluded from testifying before the FERC. However, while at the FERC, 

I presented cases publicly to the FERC Commissioners at their bi-weekly public meetings 

and was the technical contact to the Commissioners in numerous cases. Since leaving the 

7 

employ of FERC, I have filed testimony before the FERC in numerous proceedings. 

I 

8 

have also testified before the British Columbia Utilities Commission 

in Canada, the 

9 

Illinois Commerce Commission, the Maine Public Utilities Commission, the United 

\0 

States Court of Federal Claims, and the United States District Court in Florida. 

A 

11 

12 

summary of the testimony [ have filed in various proceedings is shown in Exhibit No. 

SCE-9. 

13 Q. 

PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND. 

14 A. 

15 

I received the degree of Bachelor of Science in Business and the degree of Bachelor of 

Arts in Economics from the University of Colorado, Boulder, Colorado, in May 1982. I 

16 

also received the degree of Master of Business Administration 

in Finance from the 

17 

George Washington University in Washington, DC, in December 1988. 

18 II. 

PURPOSE OF TESTIMONY AND BACKGROUND 

19 Q. 

WHAT IS THE PURPOSE OF YOUR TESTIMONY 

IN THIS PROCEEDING?




Page 4 of28 


A. The purpose of my testimony is to explain and support the formulaic methodology that 

2 SCE&G proposes to implement to adjust its annual transmission revenue requirement 

3 ("A TRR") and the transmission rates derived from the A TRR on an annual basis. I will 

4 also describe in detail how the formula rate will recover the rate of return on equity 

5 ("ROE") increment applicable to any transmission project(s) if SCE&G, in the future, 

6 seeks and receives approval from the Commission to charge an incentive for that project. 

7 Q. PLEASE LIST THE EXHIBITS YOU ARE SPONSORING, IN ADDITION TO 

8 THIS PREPARED DIRECT TESTIMONY AND THE PREVIOUSLY NOTED 

9 SUMMARY LIST OF TESTIMONIES. 

10 A. I am also sponsoring: 

II Exhibit No. SCE-I 0: Blank Formula - as it will appear in the tariff 

12 Exhibit No. SCE-II: Completed Formula - Initial Period Transmission Revenue 

13 Requirement 

14 Exhibit No. SCE-12: Statement BGIBH 

15 Q. PLEASE PROVIDE A BROAD OVERVIEW OF THE FORMULA RATE 

16 METHODOLOGY THAT SCE&G PROPOSES TO USE. 

17 A. The proposed formula enables SCE&G to calculate the net annual transmission revenue 

18 requirement and the resultant stated rates for each rate year. Except for the initial, partial 

19 rate year, each rate year is the twelve month period beginning June I. Each rate year the 

20 ATRR is based upon prior year actual cost data, with limited exceptions for ROE,



Docket ER 1O-~-OOO 

Page 5 of28 


forecasted plant additions and (if specifically authorized) forecasted construction work in 

2 

3 

4 

progress ("CWIP"). A true-up between the forecasted and actual net revenue requirement 

will be calculated each following rate year (cost year plus one) and applied as an addition 

to or subtraction from the subsequent year's net revenue requirement and resultant rates. 

5 Q. 

6 

PLEASE PROVIDE AN EXAMPLE OF HOW THE FORMULA WILL 

FUNCTION. 

7 A. 

8 

9 

10 

For service from the effective date as determined by FERC through May 31, 2010, the 

2008 rate base balances (including forecasted 2009 capital additions) and calendar year 

expenses for 2008 will be used to calculate the ATRR and the transmission rates for 

SCE&G's OATT. In May, 2010, following SCE&G's filing of its 2009 FERC Form I, 

11 

the ATRR will be recalculated using actual 2009 rate base and annual expenses. 

The 

12 

difference between the 2009 revenue requirement forecast and the actual 2009 net 

13 

revenue requirement, 

positive or negative, will be computed with interest based on 

14 

15 

16 

17 

Section 35.19(a) and used to adjust rates during the 2010 rate year (beginning June 1, 

2010). The basis for the 2010 rate year ATRR will be the same actual 2009 ATRR, 

adjusted to reflect forecasted 2010 capital additions, including the interested-adjusted 

true-up amount from the prior rate period. 

18 Q. 

PLEASE EXPLAIN WHY THE PROPOSED FORMULA IS REASONABLE. 

19 A. 

The proposed formula is virtually identical to the methodology approved by the 

20 

Commission in several recent proceedings. 

This formulaic methodology was initially 

21 

developed in the latter half of 2004 and January 2005 by Baltimore Gas & Electric




Page 6 of28 


Company ("BGE") and the operating affiliates of PHI Holdings, Inc. - Potomac Electric 

2 Power Company, Delmarva Power & Light Company and Atlantic City Electric 

3 Company. The process of developing the formulaic ATRR included examination of 

4 other formulas the Commission has authorized, such as those employed by transmission 

S 

owners ("TOs") who are members of MISO and the individual formulas of other TOs, 

6 such as Northeast Utilities Company, American Transmission Company, LLC, Boston 

7 Edison Company, and San Diego Gas and Electric Company. The BGE formula was 

8 filed at FERC in Docket No. EROS-SIS and a final formula was the result of a negotiated 

9 settlement that was approved by the Commission in April 2006. See Baltimore Gas and 

10 Electric Company, lIS FERC ~ 61,066 (2006). 

11 Subsequently, two other TOs filed very similar formulas. The Commission accepted the 

12 formula filed by Duquesne Light Company in Docket No. ER06-14S9. See Duquesne 

13 Light Company, 118 FERC ~ 61,087 (2007). The Commission also accepted the formula 

14 filed by Commonwealth Edison Company in Docket No. ER07-S83-000. See 

IS Commonwealth Edison Company, et al., 119 FERC ~ 61,238 (2007). Both of these 

16 formulas were subsequently approved by the Commission as settlement agreements. The 

17 formula proposed by SCE&G is essentially the same as that filed in August 2008 by PPL 

18 Electric Utilities Corporation and accepted by the Commission in Docket No. ER08- 

19 14S7-000, PPL Electric Utilities Corporation, 12S FERC ~ 61,121 (2008). 

20 III. FORMULA RATE IN DETAIL 

21 Q. PLEASE PROVIDE AN OVERVIEW OF SCE&G'S PROPOSED FORMULA 

22 RATE METHODOLOGY.




Page 7 of28 


A. 

The fonnula rate, to be incorporated into Attachment H of SCE&G's OATT, has three 

2 

components. 

The first is a statement that the annual transmission revenue requirement 

3 

4 

5 

and rates that comprise SCE&G's charges for Network Integration Transmission Service 

("NITS") are derived, and up-dated annually by, the fonnula. (There are similar 

statements in Schedule 7 and 8 of the OATT, i.e., statements that charges for the Finn 

6 

and Non-finn Point to Point Service are based on the fonnula.) 

The second component is 

7 

8 

9 

10 

II 

the fonnula itself, which will be included as Appendix A to Attachment H, and will 

consist of (i) the fonnula calculations of Appendix A (Transmission Fonnula Rate), and 

(ii) supporting workpapers identified as Appendix A, Attachments I through 8. Finally, 

implementation protocols describe how SCE&G will update the fonnula in future years, 

what the review procedures are, how customer challenges will be resolved, and how any 

12 

changes to the annual rate restatements will be implemented. 

These protocols will be 

13 

included in the SCE&G's OATT as Appendix B to Attachment H.. 

14 

15 

As to the fonnula itself, SCE&G proposes to use actual calendar year cost data, with 

limited exceptions for ROE, forecasted plant additions, and, when authorized by the 

16 

Commission, CWIP. 

The majority of the actual data inputs are reported annually in 

17 

SCE&G's FERC Fonn I filed with the Commission by April 30 th each year. 

SCE&G 

18 

19 

20 

proposes to use this data to populate the fonnula in May each year to produce the ATRR 

that will become effective each June 1. As discussed in more detail later in my 

testimony, SCE&G proposes to discontinue the current load-ratio share method of 

21 

charging for NITS. 

Instead, both NITS and finn Point-to-Point transmission customers 

22 

will pay the same monthly stated rate. 

The ATRR detennined by the fonnula, together 

23 

with the prior year's zonal 12 CP load, will be the basis for calculating the stated rate.




Page 8 of28 


SCE&G will post both the blank and populated formula and associated attachments on its 

2 

website. SCE&G will also submit annual informational filings to the Commission. 

3 

4 

5 

6 

Exhibit No. SCE-IO is a blank version of the proposed formula (i.e., one that has all of 

the lines and other components of the formula, but is not filled in) that will be included in 

SCE&G's OATT. As discussed above, Exhibit No. SCE-II is a version of the formula 

completed with SCE&G-specific data to establish the initial transmission revenue 

7 

requirement 

under the formula. 

8 Q. 

9 

PLEASE DESCRIBE THE RATE FORMULA THAT SCE&G IS PROPOSING AS 

SHOWN IN EXHIBIT NOS. SCE-tO AND SCE-ll. 

10 A. 

II 

12 

The formula (Appendix A) produces a net A TRR that is the sum of the return on rate 

base, operation and maintenance ("O&M") expense (including administrative and general 

expense ("A&G")), depreciation expense, taxes other than income taxes, income taxes 

13 

and revenue 

credits. 

14 

Each line of the formula consists of five columns of information or data: 

15 

(1) the line number; 

16 

17 

(2) a description of the cost item or formulaic result of the calculation on the 

line; 

18 

(3) a reference to one or more explanatory notes at the end of the formula;



Docket ERI 0- -000 

Page 90f28 


(4) either the source of the input data (a FERC Fonn I page number or 

2 

3 

attachment or SCE&G's records), or an instruction describing a 

calculation (e.g., "Sum lines 5 to 9"); and 

4 

5 

(5) the actual data input (areas shaded yellow, except data from attachments) 

or calculation applied to the data (unshaded). 

6 

7 

8 

9 

10 

Lines of the formula are grouped by category as follows: (a) Allocators; (b) Plant 

Calculations; (c) Adjustment to Rate Base; (d) Operations & Maintenance Expense; (e) 

Depreciation & Amortization Expense; (f) Taxes Other than Income Taxes; (g) 

Return/Capitalization Calculations; (h) Composite Income Taxes; (i) Revenue 

Requirement (including adjustments such as revenue credits); and (j) Notes. 

II 

The fonnula includes cost data from the prior year as reported in FERC Fonn 

1 with 

12 

13 

14 

15 

16 

limited exceptions. These exceptions are detailed in Attachments 1 through 8 to the 

formula as discussed below. The fonnula includes an estimate of new transmission plant 

additions in calculating the resulting revenue requirement for the current rate year and all 

costs (the prior year data and the estimated new transmission plant additions) are trued up 

to the current year's Fonn I. 

17 Q. 

PLEASE DESCRIBE THE COMPONENTS OF THE FORMULA. 

18 A. 

19 

As I have stated, the fonnula (shown in Appendix A and consisting of five pages) has a 

number of elements. I will describe each of these below. 

20 

(a) 

Allocators.




Page 10 of28 


This section of the fonnula develops a labor allocator using wages and salaries ("W &S") 

2 (lines I through 5), a transmission gross plant allocator ("GP") (lines 6 through 16) and a 

3 net plant ("NP") allocator (lines 17 through 18). Note A provides that the value is to be 

4 the electric portion only (the electric portion of common plant, for example). Note B 

5 specifies that the plant balance excludes construction work in progress. 

6 (b) Plant Calculations. 

7 Line 19 specifies Transmission Plant in Service for the cost year. Line 20 is used only 

8 for the true-up to remove cost year capital additions. Line 21 adds current year (cost year 

9 plus one) capital additions (time-weighted and sourced from Attachment 6). The sum of 

10 Lines 19 through 21 is the total transmission plant, line 22. 

II General ("G"), intangible ("I") and electric common plant ("C") are functionalized to 

12 transmission by the W &S allocator (lines 23 through 27). 

13 Total Plant in Service is calculated at line 28. 

14 Accumulated depreciation and amortization balances for transmission, general and 

15 electric common plant are specified at line 29 and lines 30 through 34. General and 

16 common depreciation and amortization are functionalized to transmission by the W&S 

17 allocator (lines 35 through 36). Total accumulated depreciation is calculated at line 37. 

18 Finally, net transmission plant, property and equipment is calculated at line 38. 

19 (c) Adjustments to Rate Base




Page 11 of28 

This component of the fonnula includes several calculations. 


If specifically authorized 

2 by FERC, CWIP (sourced from Attachment 6) is included on lines 39 through 40. 

3 Accumulated Deferred Income Taxes net of FASB 106 and 109 ("ADIT") shown on line 

4 41 is incorporated from Attachment 1 (a negative value). Attachment 1 provides a 

5 detailed development of the ADIT total, including functionalization of ADIT components 

6 by direct assignment or by a plant or labor allocator, as appropriate. Deferred income 

7 taxes arise when items are included in taxable income in different periods than they are 

8 included in rates. As a result, with respect to items giving rise to ADIT that are not 

9 included in the fonnula, the associated ADIT amounts are excluded as required by the 

10 Commission in Northwest Pipeline Corp., 87 FERC ~ 61,266 (1999). I note that the 

11 functionalization of ADlT to transmission on Attachment 1 is a familiar process, 

12 employing the same methodology used by many companies that prepare Statements AA- 

13 BM as required by the FERC's regulations for filings supporting increases in rates. It is 

14 also the same process used by many companies to support changes in retail rates. 

15 SCE&G elected to amortize tax credits against taxable income (lines 132 through 135), 

16 so there is no rate base deduction for Account No. 255 in the ADIT balance carried 

17 forward from Attachment 1. 

18 Plant Held for Future Use (transmission-related) (if any) is included at line 43, as 

19 specified on Attachment 5. 

20 Transmission-related prepayments are detailed on Attachment 5 and included on lines 44 

21 through 45. Prepayments are identified as either labor or plant related for




Page 12 of28 

functionalization purposes. 


The fonner are functionalized by the W&S allocator and the 

2 latter are functionalized by the net plant allocator (lines 46 through 48). 

3 Materials and supplies at line 53 consist of transmission-related balances at line 52, plus 

4 undistributed stores expenses functionalized to transmission by the W&S allocator at 

5 lines 49 through 51. 

6 Cash working capital is listed at lines 54 through 56 as one-eighth (12.5 percent) of total 

7 transmission O&M expense, which is listed at line 84. 

8 Line 57 contains the rate base adjustment identified as "Unrecovered Deferred GridSouth 

9 Costs", which is the unamortized balance of GridSouth costs. This entry will be 

10 discussed in more detail later in my testimony. 

II 

Network Credits (line 60) is a reduction to rate base equal to the net plant value of certain 

12 transmission facilities that may be built by SCE&G with funds advanced by customers to 

13 which credits will apply in the future. If applicable, this is calculated on Attachment 5. 

14 Note M explains that outstanding Network Credits "is the balance of Network Facilities 

15 Upgrades Credits due to Transmission Customers who have made lump sum payments 

16 (net of accumulated depreciation) towards the construction of Network Transmission 

17 Facilities consistent with Paragraph 657 of Order 2003-A." 

18 Finally, Rate Base is calculated at line 62 as the sum of Net Plant (line 38) and Total 

19 Adjustment to Rate Base (line 61). 

20 (d) Operations and Maintenance Expense



Docket ERI 0- -000 

Page 13 of28 


The Operations and Maintenance Expense component develops total transmission O&M 

2 at line 84, including functionalized A&G expense. Transmission O&M, per FERC Form 

3 1, is specified at line 63. Account 565 amounts are removed at line 64. Line 65 consists 

4 of the proposed annual amortization of the unrecovered balance of GridSouth costs, after 

5 subtracting GridSouth expenses (if any) recorded in Account 566. Total transmission 

6 O&M is calculated at line 66. 

7 The formula includes Account No. 561 and other costs that are the basis for SCE&G's 

8 existing Schedule 1 revenue requirement (Scheduling, Dispatch and System Control). 

9 SCE&G is not proposing to change the Schedule 1 rate in this filing. To avoid over- 

10 recovery of costs, the revenue credits specified at line 152 (developed in detail on 

11 Attachment 3) include all Schedule 1 revenues that transmission customers remit to 

12 SCE&G during the calendar year. 

13 Total A&G is specified at line 67, per FERC Form I. 

14 Pension Benefits Other than Pensions ("PBOP") expenses are removed from A&G at line 

15 69 and replaced at line 68 with a fixed amount. As explained in Note P, PBOP expenses 

16 used to calculate the ATRR will not be changed absent a filing at FERC. Property 

17 Insurance (Account 924) is removed at line 70, to be separately allocated later. Total 

18 A&G is also adjusted at lines 71 through 72 before functionalization to remove all 

19 regulatory commission expense (Account No. 928) and all general advertising (Account 

20 No. 930.1). The balance of A&G is functionalized to transmission by the W&S allocator 

21 at lines 73 through 74.




Page 14 of28 


At lines 76 through 83, certain components of A&G are directly assigned to transmission 

2 as specified by Notes G, J and F. Support for these items is shown on Attachment 5. 

3 Note G states that regulatory commission expenses included in the formula are itemized 

4 at FERC Form 1, page 351, column h and are directly related to transmission service, 

5 RTO filings, or transmission siting. Note J specifies that included amounts in Account 

6 No. 930.1 are education and outreach expenses relating to transmission. 

7 Account No. 924 and certain elements of Account No. 930.1 are specified at lines 79 

8 through 82 and are functionalized to transmission on the basis of NP (line 82). Note F 

9 instructs that only expenditures for safety-related advertising will be included on line 80. 

10 Total Transmission O&M, including functionalized A&G, is shown at line 84. 

I I (e) Depreciation & Amortization Expense 

12 Total Transmission Depreciation Expense is shown on line 96. It is the sum of booked 

13 transmission depreciation expense (line 85) plus general depreciation, intangible 

14 amortization, the electric portion of common depreciation and common amortization 

15 (lines 86 through 95) functionalized to transmission. Consistent with the 

16 functionalization of G, 1, and C, W &S is the allocation factor. 

17 (f) Taxes Other than Income Taxes 

18 Taxes Other than Income Taxes functionalized to transmission are specified at line 97, 

19 and the total functionalized balance is developed on Attachment 2 - Other Taxes. Labor- 

20 related taxes are specified on Attachment 2 and are functionalized by the W&S allocator. 

21 The remaining other taxes (property taxes and license fees) are also specified on




Page 15 of28 


Attachment 2 and functionalized by the gross plant allocator. Attachment 2 also specifies 

2 taxes not functionalized to transmission and reconciles Other Taxes to the total shown in 

3 FERC Form I. 

4 (g) Return/Capitalization Calculations 

5 Lines 99 through 125 calculate the overall rate of return on rate base ("ROR"). With the 

6 exception of ROE, the cost rate for common equity (line 121), the majority of the input 

7 data are sourced from FERC Form I data and are ultimately trued-up from FERC Form I. 

8 Note I instructs that ROE "will be supported in the original filing and no change in ROE 

9 will be made absent a filing with FERC." 

10 The long-term debt ("LTD") cost rate (line 119) is developed by dividing the LTD 

II interest expense (line 101) by total LTD outstanding (line 112). LTD interest expense 

12 may be adjusted, if appropriate, to remove interest associated with outstanding 

13 securitization bonds (line 100). 

14 LTD outstanding is total LTD per FERC Form I (line 108) adjusted for reacquired debt, 

IS non-interest bearing debt and securitization bonds. (lines 109 through III). 

16 The preferred cost rate (line 120) is the amount of booked preferred dividends (line 102) 

17 divided by preferred stock outstanding (line 113). 

18 The common equity of the capital structure (line 107) is developed at lines 103 through 

19 106 as total booked proprietary capital less the balance of preferred stock outstanding, 

20 less the balance recorded in Account No. 216.1 (Unappropriated Undistributed 

21 Subsidiary Earnings), plus a securitization adjustment (if applicable).




Page 160f28 


Total capitalization (line 115) is the sum of LTD, preferred stock and common equity. 

2 Total capitalization divided into LTD, preferred stock and common stock gives the 

3 capitalization shares shown at lines 116 through 118. 

4 Line 125 is the ROR, which is the sum of the weighted cost rates for LTD, preferred 

5 stock and common equity calculated at lines 122 through 124. 

6 Investment return (return on rate base) (line 126) is the product of the ROR (line 125) and 

7 rate base (line 62). 

8 (h) Income Taxes 

9 Federal and state income taxes (line 137) are developed consistent with the return on rate 

10 base calculated in the previous section. 

11 The tax components are Federal Income Tax Rate ("FIT"), State Income Tax Rate (or 

12 Composite) ("SIT"), and the percent ("p"), if any, offederal income tax deductible in the 

13 calculation of state income tax. These components are defined at lines 127 through 129. 

14 The composite federal/state income tax rate, 'T", is calculated on line 130, where: 

15 T = I - {[(I-SIT) * (I-FIT)]/(I-SIT * FIT * p)} 

16 The tax multiplier, T/(I- T), is calculated on line 131. The investment tax gross-up factor, 

17 1I(1-T), is calculated at line 133. 

18 The investment tax credit ("ITC") adjustment occurs at line 135, and is calculated at lines 

19 132 through 134 by multiplying the amortization of the ITC credit by the gross-up factor 

20 at line 133, the product of which is functionalized to transmission by multiplying by NP.




Page 17 of28 


I The income tax component is calculated at line 136 as the product of the tax multiplier 

2 (line 131), the investment return (line 126), and the portion of the investment return that 

3 is taxable (which is I minus the weighted debt cost rate divided by the overall rate of 

4 return). The weighted debt cost rate is calculated at line 122, and the overall rate of 

5 return is calculated at line 125. 

6 Total income taxes (line 137) are the sum of the income tax component (line 136) and the 

7 ITC adjustment (line 135). 

8 (i) Revenue Requirement 

9 The next set of calculations establishes the two measures of "Revenue Requirement": the 

10 "Gross Revenue Requirement" and the "Net Revenue Requirement." 

11 Initially, the ATRR is adjusted to reflect that some facilities booked to transmission 

12 (generator step-up units, for example) are not eligible to be included in the final OA TT 

13 ATRR. The original investment cost of these facilities is specified in Attachment 5 and 

14 shown on line 140 of Appendix A. The sum of Transmission Plant in Service (including 

IS projected capital additions), plus CWIP (if any) and Land Held for Future Use, (i.e., the 

16 sum of lines 22, 40 and 43) is reduced by the amount of excluded facilities and divided 

17 by the original balance to develop the "Inclusion ratio" shown at line 142. 

18 The Rate Base and the components of the annual transmission revenue requirement are 

19 summarized at lines 145 through 150, after adjustment by the inclusion ratio. Adjusted 

20 Gross Revenue Requirement is developed at line 151.



Docket ERIO· ·000 

Page 18 of28 


Revenue credits are entered on line 152, reduced by interest on network credits on line 

2 

3 

4 

153. Revenue Credits are detailed on Attachment 3 and are taken from Account Nos. 

447, 454 and 456. Interest on Network Credits is detailed on Attachment 5. Note M 

provides additional information on Network Credits. 

5 

6 

7 

As noted above, since the formula includes Account No. 561 and other costs that are the 

basis for the existing rate for Schedule I (Scheduling, Dispatch and System Control), the 

Revenue Credits include all revenues from Schedule I to avoid over-recovery. Also 

8 

included is revenue from the following specified secondary uses of transmission: 

(I) 

9 

right-of-way leases and leases for space on transmission facilities for 

10 

telecommunications; 

II 

12 

13 

(2) transmission tower licenses for wireless antennas; (3) right-ofway 

property leases for farming, grazing or nurseries; (4) licenses of intellectual property 

(such as scheduling software); and (5) transmission maintenance and consulting services 

to other utilities and large customers. 

14 

15 

Adjusted Gross Revenue Requirement is reduced by Revenue Credits (net of interest on 

network credits) to yield Net Revenue Requirement (line 155). 

16 Q. 

17 

18 

19 

PLEASE DESCRIBE THE CALCULATIONS RELATING TO INCENTIVE AND 

NON-INCENTIVE NET PLANT CARRYING CHARGES LISTED ON LINES 156 

THROUGH 166, WHEN INCENTIVES ARE GRANTED BY THE 

COMMISSION. 

20 A. 

21 

Upon authorization by the Commission in an appropriate filing, specified transmission 

facilities ("approved projects") can be afforded certain rate incentives, such as inclusion




Page 19 of28 


of 100 percent of CWIP in rate base andlor an incremental revenue requirement 

2 associated with an incentive ROE and associated income taxes. Approved projects will 

3 be included either in transmission plant or CWIP reported on FERC Form I. SCE&G's 

4 ownership interests in completed facilities will be included as Transmission Plant in 

5 Service shown line 19. CWIP for approved projects would be shown at line 40 of 

6 Attachment H, Appendix A and also on Attachments 6 and 7. 

7 The incremental revenue requirement for each incentive project IS determined in 

8 Attachment 7 (Transmission Enhancement Charge Worksheet), which reflects the ROE 

9 applicable to the project (e.g., SCE&G's authorized ROE including authorized basis point 

10 adders), whether it was constructed in whole or in part using customer-provided 

II financing (contributions in aid of construction ("CIAC")). The revenue requirement will 

12 also reflect different rates of depreciation accrual and different net plant balances, if 

13 applicable. 

14 The revenue requirement for an incentive project will include (I) SCE&G's base ROE 

IS (i.e., the ROE determined by application ofFERC's DCF analysis), (2) an incentive ROE 

16 as authorized by the Commission in an appropriate proceeding, and (3) correspondingly 

17 higher income taxes as compared to the ROE and income taxes associated with the 

18 facilities otherwise used to provide transmission service. These calculations are shown 

19 on Attachment 7, with inputs from Attachment 4.




Page 20 of28 


Q. 

HOW ARE ATTACHMENTS 

4 AND 7 RELATED? 

2 A. 

3 

4 

Attachment 7 applies a Fixed Charge Rate ("FCR") calculated on Appendix A to each 

project. Appendix A calculates a net plant FCR at line 158 (reflecting the "normal" ROE 

at line 121) by dividing the annual transmission revenue requirement (excluding 

5 

transmission depreciation) by net transmission plant. 

This FCR is then carried over to 

6 

7 

Attachment 7 as "Net Plant Carrying Charge without New Investment Incentive without 

Depreciation." 

8 

9 

10 

II 

Attachment 4 replicates the "Return/Capitalization Calculations" and "Income Taxes" 

sections of lines 99 through 137 of the main body of the formula. Attachment 4 uses the 

rate base calculated by the formula to calculate a new level of investment return and 

associated income taxes by changing only one variable, the base ROE, which is 

12 

incremented by 100 basis points. 

It is important to note that Attachment 4 is, in effect, a 

13 

14 

15 

16 

17 

"workpaper". Its only purpose is to calculate the "baseline" or "standard" FCR per 100 

basis points increment in ROE. This baseline is then used at Attachment 7 as a means of 

calculating the incremental return and taxes associated with any authorized increment in 

ROE (which may differ among projects). To sum up, Attachment 4 is not used to 

calculate the revenue requirement and it does not specii)' the level of incentive ROE 

18 

19 

adder that applies to any Commission-authorized 

7. 

incentive project shown on Attachment 

20 

21 

22 

On Appendix A, line 161 is calculated by subtracting the investment return (line 149) and 

income taxes (line 150) from the net revenue requirement (line 155). Line 163 is the sum 

ofline 161 and the incentive return and income taxes calculated on Attachment 4. At line



Docket ERlO-_-OOO 

Page 21 of28 


165, a net plant FCR is calculated by dividing line 163 by net transmission plant (line 

2 

3 

4 

164). A second calculation at line 166 modifies the FCR to exclude transmission 

depreciation (the "FCR-incentive") for application in the event a customer makes a lumpsum 

payment like a CIAC. 

5 

6 

Attachment 7 identifies the FCR-incentive 

Investment Incentive without Depreciation". 

as "Net Plant Carrying Charge with New 

The new investment incentive is used as the 

7 

basis for calculating an incentive annual revenue requirement for each incentive project. 

8 

Each project's 

incentive revenue requirement may reflect a different FERC-approved 

9 

level of ROE incentive than the new investment incentive developed at line 159 of the 

10 

formula as shown on Attachment 7. 

While Attachment 4 calculates a 100 basis point 

11 

12 

13 

adder for new investment, Attachment 7 is designed such that the actual new investment 

incentive is a separate input for each project, allowing (1) different adders to be approved 

by the Commission for discrete projects, or (2) no adder if none is sought or approved. 

14 Q- 

PLEASE EXPLAIN ATTACHMENT 5 - COST SUPPORT. 

15 A. 

16 

17 

18 

19 

20 

21 

22 

Notes A through Q of Appendix A provide additional detail or instructions concerning 

formula input data. This data often cannot be taken directly from FERC Form 1 without 

modification, which requires additional details to reconcile formula inputs to the reported 

data. Attachment 5 performs the same role in calculating the formula as is performed by 

Statements AA-BL in supporting the calculations on a Statement BK in a traditional rate 

filing. Since FERC Form I is publicly available electronically and the majority of inputs 

are from FERC Form I, the data required in Statements AA-BL beyond that found in 

FERC Form I is limited. The complete, populated formula, from Attachment H,



Docket ER10-_-000 

Page 22 of28 


Appendix A (including Attachments 1 through 8 thereto), will be posted on the SCE&G's 

2 

website each year before rates become effective, giving customers timely opportunity to 

3 

review the inputs to the formula rate. 

In addition, consistent with the Commission's 

4 

5 

6 

7 

8 

determination in Duquesne Light Co., 118 FERC ~ 61,087 (2007) ("Duquesne"), 

SCE&G will file the information at FERC necessary to specify any incentive plant that is 

included in rate base as CWIP in accordance with a Commission ruling, and provide 

reconciliations, where necessary, between input data in the formula and FERC Form 1 

amounts. 

9 Q. 

10 

THE COMMISSION REQUIRES THAT DEPRECIATION RATES USED IN A 

FORMULA BE FIXED ABSENT A FILING FOR AUTHORIZATION TO 

11 

12 

CHANGE THEM. 

FORMULA? 

WHERE ARE THESE RATES SHOWN IN THE PROPOSED 

13 A. 

14 

Depreciation rates applicable to SCE&G's transmission and general plant accounts are 

shown in Attachment 5. 

15 Q. 

PLEASE DISCUSS HOW SCE&G PROPOSES TO POPULATE THE FORMULA 

16 

FOR THE INITIAL 

RATE PERIOD. 

17 A. 

The initial rate period is the partial year from the effective date authorized by FERC 

18 

through May 31, 2010. 

For this period, SCE&G has populated the formula with actual 

19 

20 

21 

2008 expenses and 2008 end of period balances for plant·related items, plus the timeweighted 

estimate of transmission capital additions for 2009. In May 2010, when 

SCE&G's 2009 FERC Form 1 is available, the 2009 ATRR will be recalculated using




Page 23 of28 


2009 actual costs and investment. Differences. if any, between the ATRR estimate 

2 

3 

initially calculated and that ATRR based on actual cost will be handled as a true-up 

adjustment (pro-rated for the number of days the rate was in effect for the initial period). 

4 Q. 

5 

PLEASE EXPLAIN THE ESTIMATE AND TRUE-UP MECHANICS OF THE 

FORMULA_ 

6 A. 

The true-up mechanics are set out as protocols in Attachment H, Appendix B. 

The 

7 

calculation of the true-up with interest is accomplished on Attachment 6 -- Estimate and 

8 

True-up Worksheet. 

Each May beginning in 2010, SCE&G will complete the formula 

9 

using the data contained in the prior calendar year's FERC Form I and will prepare the 

10 

cost support schedules contained in the formula. 

The estimated ATRR in effect prior to 

II 

June 1, 2010 will first be adjusted by multiplying it by the ratio of the current year 12 CP 

12 

divided by the prior year 12 CPo 

This adjustment compensates for any growth (or 

13 

decrease) in billing determinants that occurred during the Rate Year. 

(See Step 9 on 

14 

IS 

Attachment 6.) The adjusted prior year ATRR is then subtracted from the ATRR 

calculation using actual costs for 2009, and the difference (with interest) will be added to 

16 

17 

(subtracted from) the estimated ATRR that will be effective on June 1, 2010. 

process will be repeated each year subsequent to 2010. 

This 

18 

The formula templates, exhibits and cost support will be posted on SCE&G's website. 

19 

Consistent with the Commission's 

recent Duquesne order, SCE&G will also make an 

20 

informational filing at FERC. 

Thus, the Commission and SCE&G's customers have an 

21 

22 

opportunity to review the formula calculations and supporting data before the changes 

take effect, and to challenge the rate recalculations.




Page 24 of28 


1 Q- 

2 

WILL SCE&G'S CUSTOMERS OR OTHER INTERESTED PARTIES HAVE AN 

OPPORTUNITY TO REVIEW AND CHALLENGE THE ANNUAL RATE 

3 

RESTATEMENTS 

UNDER THE FORMULA? 

4 A_ 

S 

6 

7 

Yes. Again, the protocols in Attachment H, Appendix B provide the details. The review 

procedures provide 171 days after the publication date for SCE&G's transmission 

customers, the Public Service Commission of South Carolina and other interested parties 

to review and submit a written challenge to specific items included in the formula. These 

8 

interested parties also have 150 days from the publication 

date to serve reasonable 

9 

information requests on SCE&G. 

Interested parties must make a good faith effort to 

10 

11 

12 

13 

14 

15 

16 

17 

submit consolidated sets of information requests that limit the number and overlap of 

questions. SCE&G will make a good faith effort to respond to these requests within 15 

days. If the parties have not been able to resolve any such challenge within 21 days, the 

party bringing the challenge will have an additional 21 days to file a formal complaint 

with the Commission. SCE&G will have 30 days to respond. These procedures do not 

limit in any way SCE&G's right to file to change the formula or its inputs under Section 

205 of the Federal Power Act, or the right of any other party to file a complaint 

requesting such changes under Section 206. 

18 Q- 

19 

20 

IN YOUR OPINION DOES THE FORMULA RATE PROPOSED BY SCE&G IN 

THIS PROCEEDING CONFORM TO COMMISSION PRECEDENT WITH 

RESPECT TO FORMULA RATES? 

21 A_ 

Yes. The formula operates identically to numerous formulas already accepted and 

22 

approved by the Commission. 

The true-up mechanism reflects Commission precedent



Docket ER 1O·~·OOO 

Page 25 of28 

Exhibit No. SeE·8 

and ensures there is no over-recovery with respect to charges assessed as the result of the 

2 

application of the formula. The classification, functionalization and allocation factors 

3 

used for the cost items reflect standard Commission ratemaking. 

Furthermore, all data 

4 

5 

used in Appendix A is taken directly out of the FERC Form I or reconciled back to the 

FERC Form I in the Attachments to Appendix A. 

6 Q. 

7 

8 

PLEASE DISCUSS SCE&G'S PROPOSAL TO BEGIN CHARGING FOR NITS 

THROUGH A STATED RATE, REPLACING THE CURRENT LOAD RATIO 

SHARE METHODOLOGY. 

9 A. 

SCE&G's proposal to use a stated rate based on a 12 CP divisor is consistent with what 

10 

the Commission has approved for other utilities. 

SCE&G's proposal to institute a stated 

II 

12 

NITS rate reflects its desire to provide a degree of rate certainty to purchasers of its 

network transmission services who currently face constantly changing rates because the 

13 

current NITS rates are calculated using the load ratio methodology. 

In other words, 

14 

SCE&G's proposal is consistent with and superior to the pro-forma OATT rate design 

15 

because it is simpler and more predictable for all transmission users. 

The Commission 

16 

17 

recognized the validity of this concern, when it approved Pennsylvania-New 

Maryland Interconnection, Inc.'s proposal of a stated rate for network service: 

Jersey- 

18 

19 

20 

21 

22 

23 

24 

The stated rate for network service is intended to provide greater rate 

certainty to suppliers and customers than exists under the load ratio share 

approach, because the ultimate transmission rate for a supplier under the 

load ratio share method will change depending not only on variations in 

the loads served by a particular supplier but on the loads served by others. 

Pennsylvania-New Jersey-Maryland Interconnection, LLC, 81 FERC ~ 61,257, at n. 44 

(1997). See also PJM Interconnection, LLe., et aI., 108 FERC ~ 61,318 (2004);



Docket ERIO·_-OOO 

Page 26 of28 


Southwest Power Pool, 96 FERC ~ 61,034 (2001); Alliance Cos., et al., 94 FERC 

2 

3 

~ 61,070 (2001), order on reh'g, 95 FERC ~ 61,182 (2001). The Commission has 

approved a stated rate for network service offered by several other transmission 

4 

providers, 

including Sierra Pacific Power Co. and Nevada Power Co. (Docket No. 

5 

6 

ER07-1371-000, 121 FERC ~ 61,160 (2007)); Northwestern Corp. (Docket No. ER07- 

46-000, 117 FERC ~ 61,293 (2006)); Sierra Pacific Resources Operating Cos. (Docket 

7 

No. ER03-1328-000, 

108 FERC ~ 61,023 (2004)); and International Transmission Co., 

8 

9 Q. 

10 

II 

12 

13 

LLC (Docket No. EROO-3295-000, 92 FERC ~ 61,276 (2000)). 

PLEASE DISCUSS HOW THE FORMULA ACCOMODATES SCE&G'S 

PROPOSAL TO RECOVER, BEGINNING JUNE 1,2010, DEFERRED COSTS 

("GRlDSOUTH COSTS") IT INCURRED IN THE UNSUCCESSFUL ATTEMPT 

TO FORM THE PROPOSED REGIONAL TRANSMISSION OPERATOR, 

GRlDSOUTH. 

14 A. 

15 

On Attachment 5 - Cost Support, under the section title "Grid South Surcharge Cost 

Support", is shown for the year beginning 2004 the GridSouth costs SCE&G incurred 

16 

through 2003. 

This balance is discussed and supported in detail in the testimony of 

17 

SCE&G witness Charles A. White, Exhibit Nos. SCE-6 and SCE-7. 

Attachment 5 also 

18 

shows the calculation of the carrying charges (at the formula-determined 

ROR) for the 

19 

years 2004 through 2009 and the first five months of 20 10. This total - GridSouth costs 

20 

at BOY 2004 plus carrying charges through May of 2010 - is $24,967,230. 

It is the 

21 

22 

amount that SCE&G proposes to amortize (beginning June 1, 2010) over the five rateyear 

period beginning June 1,2010 and ending May 31,2015, as shown on Attachment 5.



Docket ER10- -000 

Page 27 of28 


The unamortized balance of these deferred costs is also shown on Attachment 5 and will 

2 

3 

4 

5 

6 

7 

be included as a rate-base adjustment on line 57 of the formula, Appendix A. The annual 

amortization (an expense) is included at line 65 of the formula. Thus, the annual expense 

and the return and taxes on the unamortized balance of GridSouth costs will be a 

component of the net revenue requirement from which the transmission service rate is 

derived. After the amortization period, GridSouth costs will have no effect on the 

transmission rate. 

8 Q, 

ARE GRID SOUTH COSTS PROPOSED TO BE RECOVERED IN THE INITIAL 

9 

(PARTIAL) 

RATE PERIOD? 

10 A. 

No. 

Even though the development of the GridSouth costs is shown in Attachment 5 of 

II 

Exhibit SCE-II, 

for calculative convenience and to reduce the amount of the initial rate 

12 

13 

increase, SCE&G proposes that recovery of the GridSouth surcharge begin (and end) 

over a full rate year; hence, the proposed beginning at June 1, 20 I0 and termination at 

14 

May 31, 2015. 

The fact that the amortization of the surcharge does not begin until the 

15 

16 

17 

18 

20 10 rate year is memorialized in Note Q of Appendix A. SCE&G also proposes that at 

the end of the five-year amortization period, SCE&G will compare surcharge revenues 

collected against surcharge costs and true-up the two amounts on a one-time basis during 

the rate year beginning June 1,2016. 

19 Q. 

WHAT IS THE RATE IMPACT OF THE GRIDSOUTH SURCHARGE? 

20 A. 

The rate impact of the surcharge is estimated to be about $0.13 per kw/month. 

The initial 

21 

monthly transmission rate (2008 costs) is $1.75 per kw/month, so the surcharge will be




Page 28 of28 


about an 8% increase beginning June I, 2010. The $0.13 impact was calculated based on 

2 2008 costs by multiplying the return and tax components times the unamortized balance 

3 of the Grid South costs, adding the annual amortization and dividing by the load. This 

4 percentage increase is a rough estimate and may be less, since, as proposed, the 

5 GridSouth costs will be a part of a rate calculated primarily on 2009 actual (Form I) 

6 costs. 

7 Q. PLEASE DESCRIBE EXHIBIT NO. SCE-12. 

8 A. This exhibit is a traditional (combined) Statement BGIBH. Its purpose is to show 

9 SCE&G's transmission customers the estimated impact on their transmission bills of the 

10 proposed rates in this filing compared to the current rates. 

II Q. DOES THIS CONCLUDE YOUR TESTIMONY? 

12 A. Yes.


AFFIDAVIT 

CITY OF WASHlNGTON ) 

) 

DISTRICT OF COLUMBIA ) 

Alan C. Heintz, being duly sworn, deposes and states that the attached are his 

sworn testimony and exhibits, and that the statements contained therein are true and 

correct to the best of his knowledge, information and belief 


this I5 st day of September, 2009 

My Commission Expires: June 30, 2014




EXHIBIT 

NO. SCE-9 

SUMMARY OF ALAN C. HEINTZ TESTIMONY 

IN PRIOR PROCEEDINGS

SUMMARY OF TESTIMONY 


EXPERIENCE 


Page 1 of 10 

PERC ER95-836-000 Maine Public Service Company Maine Public Service 1995 Rates, Terms and Conditions for 

Company Open Access Transmission 

Services 

2 PERC ER95-854-000 Kentucky Utilities Company Kentucky Utilities Company 1995 Rates, Tenns and Conditions for 

Open Access Transmission 

Services 

3 PERC ER95-1686-000 Northeast Utilities Service Northeast Utilities Service 1996 Rates, Terms and Conditions for 

ER96-496-000 Company Company Open Access Transmission 

Services 

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4 FERC ER96--58-000 Allegheny Power Services Allegheny Power Services 1995& 1996 Rates, Terms and Conditions for 

Corporation Corporation Open Access Transmission 

Services 

5 PERC OA96-138-000 Consolidated Edison Company Consolidated Edison 1997 Rates, Terms and Conditions for 

of New York, Inc. Company of New York, Inc. Open Access Transmission 

Services 

6 PERC ER96-1208-000 Interstate Power Company Interstate Power Company 1996 Rates, Tenns and Conditions for 


Services 

7 British British Columbia Hydro and Bonneville Power 1997 Rates, Terms and Conditions for 

Columbia Power Authority Administration Open Access Transmission 

Utilities 

Services 

Commission 

9-/5-09


Page 2 of 10 

8 FERC ER98·1438·000 Cincinnati Gas & Electric Midwest ISO Transmission 1998 & 1999 Rates, Terms and Conditions for 

EC98·24·000 Company, et al. (Midwest Owners Midwest ISO Tariff 

Independent System Operator) 

9 FERC EC98·2770·000 American Electric Power Midwest Independent 1999 Reasonableness of the conditions to 

ER98·2770·000 Company, Inc. and Central & System Operator be placed 011 the merging parties 

ER98·2786·000 Southwest Corporation Transmission Owners 

10 Illinois 99·0117 Commonwealth Edison Commonwealth Edison 1998 Cost of service for Retai I 

Commerce Company Company Distribution Services Tariff 

Commission 

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II FERC ER99·3110·000 Nevada Power Company Nevada Power Company 1998 Rates, Terms and Conditions for 


Services 

12 FERC ER99·44 I5·000 Illinois Power Company Illinois Power Company 1999 Rates, Terms and Conditions for 


Services 

13 FERC ER99·4470·000 Commonwealth Edison Commonwealth Edison 1999 Rates, Terms and Conditions for 

Company Company Open Access Transmission 

Services 

14 U.S. District 92-35·CIY·ORL· Florida Municipal Power Florida Power and Light 1999 Rates, Terms and Conditions for 

Court,FL 3An Agency VS. Florida Power and Company Network Service in an anti-trust 

Light Company 

case 

15 U.S. Court of 97·268C Carolina Power & Light Carolina Power & Light 1999 Cost recovery of Decontamination 

Federal Claims. Company vs. U.S. Department Company & Decommissioning Fund 

DC of Energy Assessments 

9-15·09


Page 3 oflO 

16 FERC ER98·496·006 San Diego Gas & Electric Dynegy 1999 Rates for Must Run units 

ER98·2160·004 

17 FERC EROO·980·000 Bangor Hydro Electric Bangor Hydro Electric 1999 Rates, Tenns and Conditions for 


Services 

18 Maine Public 99·185 Bangor Hydro Electric Bangor Hydro Electric 2000 Rates, Terms and Conditions for 

Utilities Company Company Open Access Transmission 

Commission 

Services 

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19 FERC ELOO·98·000, et aJ. Dynegy Power Marketing, Inc, Dynegy Power Marketing, 2000 Nexus between fuel and emissions 

et aJ. Inc. costs and the market prices in 

California 

20 Illinois No. 01·0423 Commonwealth Edison Commonwealth Edison 2001 Direct, Rebuttal and Surrebuttal: 

Commerce Company Company Cost of service for Retail 

Commission Distribution Services Tariff 

21 FERC EROI·2992 Commonwealth Edison Commonwealth Edison 2001 Rates, Terms and Conditions for 


Services 

22 FERC EROI·123.004 Midwest ISO Transmission Midwest [SO Transmission 2001 Super Region Adjustment for the 

Owners Owners MISOIARTO Super Region 

23 FERC EROI·2999 Illinois Power Company Illinois Power Company 2001 Rates, Terms and Conditions for 


Services 

9·15-09

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Page 4 of 10 

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24 FERC EROI·3142, et. al Midwest ISO Midwest ISO Transmission 2001 Revised treatment of Network n ~. 

Owners Upgrades ~ .... 

25 FERC ERO1·3142, et. al Midwest ISO Midwest ISO Transmission 2001 Uncertainties that support a higher II .... 

Owners ROE "- " 

" 

"- '" 

Dynegy, Mirant, Reliant and 2001 & 2002 Costing of emissions and start-up " 

26 FERC ELOOO·95-045. et.al San Diego Gas & Electric 0 

0 

Company v. Sellers of Energy Williams costs 

and Ancillary Service Into 

'" 

Markets Operated by the 

CALISO ... 

I 

I 

"w 

27 FERC EC02-23 & ER02· Trans-Elect, Inc., et. al Trans-Elect, Inc. 2001 & 2002 Support of rates and ratemaking 

320 methodology for new transmission 

company 

28 FERC Sithe New Boston, LLC Sithe New Boston, LLC 2001 & 2002 Cost of Service for Must Run Unit 

29 FERC RMOI-12 FERC Technical Conference SeTrans 2002 Allocation ofFTRs/CRRs 

30 FERC EL02-lll Midwest ISO & PJM Midwest ISO Transmission 2002 Through and Out Rates 

Owners 

31 FERC ER02-2595 Midwest ISO Midwest ISO Transmission 2002 Cost Allocation for FTR and 

Owners 

Market Administration 

32 FERC ER03-37 Sierra Pacific Resources Sierra Pacific and Nevada 2003 Ancillary Service Rates 

Power 

9-/5-09


Page 5 of 10 

33 FERC ER03-626 Empire District Electric Co. Empire District Electric Co. 2003 Cost of Service; Wholesale 

Requirements Customers 

-- 

34 FERC EL-02·25·00 I, et. al Intermountain, Holy Cross, Public Service Co. of 2003 Fuel Adjustment Clause 

Yampa and Aquila 

Colorado 

35 FERC ER03-959 Exelon Framingham LLC. !:ll!!. Exelon Framingham LLC, et 2003 Production Cost of Service 

al. 

36 FERC ER03-1187 MidWest Generation, LLC Commonwealth Edison 2003 Black Start Rates 

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37 FERC ER03-1223 Montana Megawatts I, LLC, !:l Montana Megawatt 2003 Production Formula Rates 

l!! 

38 FERC ER03-1335 Commonwealth Edison Commonwealth Edison 2003 Transmission Tariff Rates 

39 FERC ER03-1354 Black Hills Power CompanY,!:l Black Hills Power Company, 2003 Joint transmission Tariff Rates 

l!!. 

!:ll!!. 

40 FERC ER03-1328 Sierra Pacific Resources Nevada Power 2003 Transmission Tariff Rates 

41 FERC EL02-111, et. AI Midwest ISO and PJM Midwest ISO Transmission 2004 Long-term Transmission Pricing 

Transmission Owners Owners Plan 

42 FERC ER05-14 Sierra Pacific Resources Sierra Pacific 2004 Transmission Tariff Rates 

43 FERC ER05-26 Mirant Kendall, LLC Mirant Kendall, LLC 2004 Reliability Must Run Agreement 

and Rates 

9-15-09


Page 6 of 10 

~. 

44 Illinois No.04-0779 NICOR Gas Company NICOR Gas Company 2004 Distribution Service Embedded 

~. 

Commerce 

Cost of Service Study 

~ 

.... 

Commission 

~ 

45 FERC Er05-163 Milford Power Company LLC Milford Power Company 2004 Reliability Must Run Agreement -.... 

LLC and Rates 

'" 

46 FERC EL02-111, et. al Midwest ISO and PJM Midwest ISO Transmission 2004 Seams Elimination II 

Transmission Owners Owners 

I 

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47 FERC ELOO-95, et. al SDG&E V. Sellers, et a!. Portland General Electric 2005 California Refund Proceeding 

Company 

48 PERC ER05-447 Midwest ISO Midwest ISO Transmission 2005 Schedule 10 & 17 Recovery for 

Owners 

Grandfathered Agreements 

49 FERC EL02-11I, et. al Midwest ISO and PJM Midwest ISO Transmission 2005 Seams Elimination 


50 PERC ER05-860 Whiting Clean Energy Whiting Clean Energy 2005 Cost Based Power Rates 

51 FERC ER05-903 Con. Ed. Energy Mass., Inc. Con. Ed. Energy Mass., Inc. 2005 Reliability Must Run Agreement 


52 FERC EL02-111, et. al Midwest ISO and PJM Midwest ISO Transmission 2005 Seams Elimination 


53 FERC ER05-1050 AmerGen Energy Company, AmerGen Energy Company, 2005 Reactive power charges 

L.L.C. 

L.L.C. 

9·15·09


Page 7 oCIO 

~ 54 Illinois No.05-0597 Commonwealth Edison Co. Commonwealth Edison Co. 2005 Distribution Service Embedded n 

~ 

Commerce 


Commission .... 

55 FERC ER05-1179 Berkshire Power Company, LLC Berkshire Power Company, 2005 Reliability Must Run Agreement " "- 

LLC and Rates " '" 

"- 

" 0 

56 FERC ER05-1243 Basin Electric Power Basin Electric Power 2005 Revised Transmission Cost of 0 

II 

Cooperative Cooperative Service 

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57 FERC ER05-1304 & Mystic I, LLC and Mystic Mystic I, LLC and Mystic 2005 Reliability Must Run Agreement 

ER05-I305 Development, LLC Development, LLC and Rates 

58 FERC ER05-273 Midwest ISO Midwest ISO Transmission 2005 Proper Pricing for Regional Non- 

Owners 

firm Redirects 

59 FERC ER05-515 PHI and BGE PHI and BGE 2005 Transmission Formula Rates 

60 FERC EL05-19 Southwestern Public Service Southwestern Public Service 2005 Production rates and Fuel 

Company Company Adjustment Clause, 

61 FERC ER06-427 Mystic Development, LLC Mystic Development, LLC 2006 Reliability Must Run Agreement 


62 FERC ER06-822 Fore River Development, LLC Fore River Development, 2006 Reliability Must Run Agreement 

LLC 


63 FERC ER06-819 Consolidated Edison Energy Consolidated Edison Energy 2006 Reliability Must Run Agreement 

Massachusetts, Inc Massachusetts, Inc and Rates 

9-15-09

64 FERC ER07-169 Ameren Energy Marketing Ameren Energy Marketing 2006 Ancillary service rates 

Company 

Company 


Page 8 oflO 

65 FERC ER06-1549 Duquesne Light Company Duquesne Light Company 2006 Transmission Formula Rates .... 

-.... 

" 

" 

66 FERC ER07-170 Ameren Energy, Inc. Ameren Energy, Inc. 2006 Ancillary service rates II -.... '" 

67 FERC ER06-787 Idaho Power Idaho Power 2006 & 2007 Transmission Formula Rates II 

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68 FERC ER07-562 

69 FERC ER07-583 

Trans-Allegheny Interstate Line Trans-Allegheny Interstate 

Company 

Line Company 

Commonwealth Edison Commonwealth Edison 

2007 Transmission Formula Rates 


70 FERC ER07-1171 

Arizona Public Service Co. 

Arizona Public Service Co. 


71 Illinois No. 07-0566 Commonwealth Edison Co. Commonwealth Edison Co. 2007 Distribution Service Embedded 

Commerce 


Commission 

72 FERC ER07-1371 

Sierra Pacific Resources 

Sierra Pacific Resources 

2007 Transmission Rates 

73 FERC ER08-28I 

Oklahoma Gas & Electric 

Oklahoma Gas & Electric 


74 FERC ER08-313 

Southwestern Public Service Southwestern Public Service 2007 Transmission Fonnula Rates 

75 FERC ER08-386 

Potomac-Appalachian 

Potomac-Appalachian 

Transmission Highline, LLC Transmission Highline. LLC 


76 FERC ER08-374 

Atlantic Path 15, LLC 

Atlantic Path 15. LLC 

2007 Transmission Rates 

9-15-09


Page 9 oflO 

~. 

77 Illinois No. 08-0363 NICOR Gas Company NICOR Gas Company 2008 Distribution Service Embedded 

~. 

Commerce 


~ 

Commission 

.... 

~ 

78 FERC ER08-951 PSEG Energy Resources & PSEG Energy Resources & 2008 Reactive Power Charges '- 

Trade, LLC Trade, LLC II " 

'-"0 '" 

79 FERC ER08-1233 Public Service Gas & Electric Public Service Gas & 2008 Transmission Formula Rates E 

Company 

Electric Company 

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0 

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80 FERC ER08-l457 PPL Electric Utilities Corp. PPL Electric Utilities Corp. 2008 Transmission Formula Rates 

81 FERC ER08-1584 Black Hills Power Black Hills Power 2008 Transmission Formula Rates 

82 FERC ER08-1600 Basin Electric Power Coop Basin Electric Power Coop 2008 Transmission Rates 

83 FERC ER09-36 Prairie Wind Transmission, LLC Prairie Wind Transmission, 2008 Transmission Formula Rates 

LLC 

84 FERC ER09-35 Tallgrass Transmission, LLC Tallgrass Transmission, LLC 2008 Transmission Formula Rates 

85 FERC ER09-75 Pioneer Transmission, LLC Pioneers Transmission, LLC 2008 Transmission Formula Rates 

86 FERC ER09-255 Nebraska Public Power District Nebraska Public Power 2008 Transmission Formula Rates 

District 

87 FERC ER09-528 ITC Great Plains, LLC ITC Great Plains, LLC 2009 Transmission Formula Rates 

9-15-09

88 Illinois 

Commerce 

Commission 

ER08-0532 Commonwealth Edison Co. 


Page 10 of 10 

Commonwealth Edison Co. 2008 Distribution Service Embedded 


89 PERC ER09-J598-000 Nevada Power Company Nevada Power Company 

2009 Production Cost Formula Rate 

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9-15-09




EXHIBIT 

NO. SCE-tO 

FORMULA RATE (BLANK SHEETS)


Exhib' No seE· 10 

AH.chmentH·2 

PSge 1 of 20 

Appendix 

A 

v .. , 

V.llow-ahad.d cello are Input eel .. 

~' 

Waga. & Salary Allce.'on Facio. 

Tran,m;'sian Wagoe. Expm.e 

p354.21 b 

p354.28b 

Tolal Wages E>


Exhib' No. seE. 10 

AltachmenlH·2 

Page2of20 

ConslNctlon Work In Prall"'. (CWIP) 

39 CWIP (weighted by manlh.e>t 

75 Gen.,a!Expen ... Alloc~_d to Transmiulon 

pJ23.1Q7.b 

{Nata Pj (Attachment5) Q,456.53Q 

(Note P) (Attachment5) 

, 

p323.185b 

(Note E) 

p3231a9b 

323.1Q1b 

Line 67 + ~8 Sum (Lines 6Q to 72) 9,45a,s3Q 

line 5 00000% 

(Lin.. 73 -74) 

Directly Assigned A&G 

75 Regulalory Commission Exp koount928 T,ammi.sion Related 

77 Gener.1 Ad..,rtisinp E"p koount930.1 Educalion & Ou~e.ch 

78 Sublotal_ Tranamal"n Raiobod 

.. 

Property In.uranee 

General """"rti.ing 

Tolal 

Aco>unl 924 

Exp koount9~0.1 Safeii' 

Net Plant Altocation Factor 

" 

"" 

"' 

" 

" 

A&G Alloe.ted 10 Transmissbn 

Tola) Tren.m".lonO&M 

(Note 0) 

(NotaJ) 

(Nole F) 

AttachmentS 

Attaohment5 

(Une 7e + 77) 

(line 70) 

AttachmentS 

(Line 7Q +aO) 

Lim' IS 0.0000% 

(LiM 81 -52) 

(Un. 66+ 75 + 78 + 83)


Exhibi No. SCE·l0 

AttachmentH-2 

Page ~ of 20 

D&preciation 

E>cP"'s. 

65 Tran.minion Oep,,"ciallonExpensa 

(Note "I) 

p336.7b 

B6 General Plant Deprecia~on. Electnc Only 

87 Inlan9ib~PlantAmornUibon - Eleclnc Only 

88 Total 

89 W. e &. Sal. Allcealen Facbr 

gO Gen.raiDep,",elation A.oeated to Tr..... milslon 

(Note Aand "I) AttachmentS 

(Note Al 

AttachmentS 

(Line 86 + 87) 

Line 5 0.0000% 

(Line sa· ag) 

• 

91 Common Plant Depreoiation. Electric Only 

Q2 Common PlanlAmOftization· Electric Only 

93 Tolal 

94 W. ,,&. Sola Alloea"'" FaCbr 

95 CORYnonD.p.-elation· Eteclric Only Allocaad to Transtnia.lon 

(Note A and "I) Attachment5 

(Note A) Attachment5 

(Line9' +Q2) 

LineS 00000% 

(Linen"g4) 

98 Total T.an ..m.alon O.p,,"cIaOon & Amortiution 

(lin.S5+DO+95) 

gJ Tau .. Oth .. than Incom>Taxas 

Attachment2 

98 TotalTn .. OIll.rlnan (ncome 

Lin. 117 

Long hrmlnte..-t 

long hrm Inl


E


ExhiblNo $CE-10 

Atl!ichmentH-2 

PageSof20 

Noh". 

B E"W. conm.c~onWOO; In Progr... 

l .... 2O ,,,,,,,,,,.,. ~BW T,""mi.""" PIon! Add""'"" for the ' ... rem 'f68I while line 21 adO. bod 11105. odd,,,", _hted by the months placed in ~ 

C Tr"",m',ssoonPortionOn~ 

D ConSloction WorI: "' Pr09'_ (CWlP) ~ ,aI o! zero unti tile Comm .. ,io" OrderS" ohong" 

E All Regulatory Commi55"" E>:pefl'" 

G RogulIIlDry Comm~,ion Expe.,.,. droctl\' relaloO to trBnsm .. ,,,,,, ...v.:e, RTO fling'. or tr'n, .. ,SIOO 'img lern~eO In Form I OIl51.h 

H The '00..,11\' effeclilte ilcome ... ral •. ""Of. FIT ~ lIle Fodor., WlComeIBx ,.I!: SIT i."'. s- fteome fa< l'!Ite ano p = 

"\he pe,,:-um poymonts 

Inot~"",u","IoI"der


Exh'lb'lt No. SCE-10 

Attachment H·2 

Page 6 of 20 

ADlT· 282 

ADlT-283 

ADlT·190 

Subtotal 

Wages & Salary Allocator 

Gross Plant Allocator 

All Transmission 

ADIT Allocated to Transmission 


Attachment -1 - Accumulated Deferred Income Taxes (ADIT) Worksheet 

On~ 

Transmission Plant Labor 

Related I2Ii!! 

0 

0 0 0 

0 

0 

0.0000% 

00000% 

100% 

- 

Column C ADIT ~ems (below) relate only to Non'£!earicOperations (e.g. Gas) OR Production OR l\ems NOT 'Included in the ADIT calculation above 

Column C amounttOlals 0 

Check total- Agrees to Recoil. (Attachment 1-2)



Attachment H-2 

Page 7 of 20 

Attachment 1- Accumulated Deferred Income Taxes (ADIT) Worksheet 

ADlT-190 

A B C 

Production 

Or Other 

D 

Only 


I!IJ>/ B!!ll!!i ~ ~ 

- 

E F G 

Plant 

r!Otlflcatll 

Add Pension Ex and fAS 1~ from Ace( 283 0 

Subtotill- 234 0 0 0 0 0 

Less FASa 109 Above ilool se rate removed 0 0 0 0 0 

'''''' 

0 0 0 0 0 

Inslrucliofls 

lor AccOtJnll90: 

,. ADIT ~ems related only to Non-Electric Operations (e,g" Gas, Water, Sewer) or Product;!)n are dired.ly assigned 10 COlumn A 

2. ADIT items related only 10 TransmiSsion are directly assigned 10 Column B 

3. ADlT items related Plant and not in Columns A & B are directly assigned 10 Column C 

4. ADiT items related 10 Labor and nol in Columns A & B are directly assi~ to Column 0 

5. Deferred income taxes arise when Items are included in taxable income in different periods lhan Ihey are included in rates therefore, ilthe item giving rise I(lthe ADIT is not 

included ill the rOfTTlUla,li1eassociated ADiT amount shall be excluded


Exhibit No. SCE-1 0 


Page 8 of 20 

Attachment 1- Accumulated Deferred Income Taxes (ADlT) Worlrsheet 

AD/T· 282 

A B C 

Production 

Or Other 

D 

Only 


Plant 

E F G 

Total Related R~."d ..,.,.d R~.'" .hmJfI,"/oo 

Subtotal- 275 0 0 0 0 0 

Less FASB 109 Above ifnol se ralel removed 0 0 0 0 0 

Less FASB 106 Above ifnot removed 0 0 0 0 0 

,.., ". 0 0 0 0 0 

Instructions for A~Dunt 282' 

1. ADIT items related only to Non-Electric Operations (e.9., Gas. Water. Sewer) or Productioll are directly assigned to Column A 

2. ADIl items related only to Transmission are directly assigned to Column B 

3. ADIT items related Plan! and not in Columns A Iii B are directly assigrled 10 Column C 

4. ADIT items related to labor and 111Min Columns A Iii B are directly assigoed 10 Column 0 

5. Deferred income taxes arise when ilems are irlCh.lded in taxable income in different periods thanthey are included in rales there/ore. if the item giving rise to the ADiT is not 

included inthe formula. the associaled ADiT amounl shall be excluded




Page 9 of 20 

Attachment 1- Accumulated Deferred Income Taxes (ADlTJ Worlcsheet 

ADIT-283 

- 

A B C 

_to. - 

D 

E F G 

Producrion 

Only 

Or Other Transmission Plant 

R""" 

rm.l 

~' 

, 

~ 

Instructions/or 

Aoxounl28J: 

1. ADIT items related only to Non-Electric Operations (e,g.. Gas, Water, Sewer) or Production are directly 8ssiglled til Column A 

2. ADIT items related only 10 Transmission are directly assigned to Column B 

3. ADIT items related Plant and not in ColurTf1s A & B are directly assigned to Column C 

4. ADiT i\ell1s related 10 labor and nol in Columns A & B are direclly assi!1'OO 10 Column D 

5. Deferred income taxes arise when items are included in taUble ir.::ome in dirrernl'll periods than they are included in rates therefore, if the item giving rise to the ADIT is not 

included in the formula,the associated ADIT amount ~II be ucluded




Page 10 of 20 


Attachment 

2 - Taxes Other Than Income Taxes Worksheet 

Other 

Taxes 

Page 263 

Col (i) 

Allocator 

Allocated 

Amount 

Plant Related 


Total Plant Related o 0.0000% o 

Labor Related Wages & Salary AI/ocator 

Total Labor Related o 0.0000% o 

Other Included 


Total Other Included o 0.0000% o 

Total Included 

o 

Currently 

Excluded 

Total as reported on p. 263(i) o


Exhibit No.SCE-10 


Page 11 of 20 



4470004 - Transmission Short-Term (Note 1) 


3 4470004 - 5T AncHIa ry Services Revenue (Note 1) 

4 4470006 - LT Ancillary Services Revenue (Note 1) 


Attachment 3 - Revenue Credit Workpaper 

Total Account 

(Sum Lines 1-5) $ $ 



Amount 



7 land Rental Revenue - Generation Property 








15 Total Rent Revenues (Sum Lines 7-9) $ $ 


16 Transmission of Electricity for Others - Form 1, pg 330 less Network Customers & Woodland Hills (Note 1) 

17 Ancillary 1 & 2 Charges - Form 1, pg. 328, column m/7 less Network Customers (Note 1) 

18 Transmission of ElectriCity for Others - Network Customers 

19 Ancillary 1 & 2 Charges - Network Customers (Note 1) 

20 Woodland Hills Contract{Note 1) 

21 Total Other Electric Revenues (Sum Lines 11-13) $ $ 

22 Totals (Line 5+ 15 +21) ~$_==.;.._ $ 

~ 


which the cost of the service is recovered under this formula, except as specifically provided 

for elsewhere in this Attachment or elsewhere 'In the formula will be included as a revenue 

credit or included in the peak on line 170 of Appendix A. Types of revenue included as a 




assets: (1) right-of-way leases and leases for space on transmission facilities for 

telecommunications; (2) transmission tower licenses for wireless antennas; (3) right-of-way 


(including a portable oil degasiflcation process and scheduling software); and (5) 


high-voltage substation maintenance, safety training, transformer oil testing, and circuit 



to the revenue requirement. 



the Directly Assigned Facility Charges are not included in the Rates, the associated 

revenues are not included in the Rates.


Exhibit No. SCE-1 0 


Page 12 of20 


Attachment 4 • 100 Basis Point Increase in ROE 

Net Plant New Investment Incenitive@ 

100 Basis Points 

A 


New Investment ROE Incentive and Income Taxes 

o 

B Net Plant New Investment Incenitive@10DBasisPoints 1.00% 

Return 

Calculation 

145 Rate Base (line 62 * 142) 0 

long Term Interest 

99 Long Term Interest p117.62e through 66c 0 

101 Long Term Interest (Line 99 -100) 0 

102 Preferred Dividends enter positive p118.29c 0 

Common Stock 

103 Proprietary Capital p112.16e 0 

10. Less Preferred Stock (Acct. 204) enter negative (Line 113) 0 

106 Less Account 216.1 enter negative E!112.12c 0 

107 Common Stock (Sum Lines 103 to 106) 0 


108 Long Term Debt p112, 18c through 23c 0 

109 less Reacquired Debt enter negative p112.19c 0 

110 less Non-interest bearing debt enter negative Attachment 8 0 

112 Total long Term Debt (Sum Lines 108 to 111) 0 

113 Preferred Stock p112.3c 0 

114 Common Stock Line 107 0 

115 Total Capitalization (Sum Lines 112 to 114) 0 

116 Debt % Total long Term Debt (Line112/11S) 0% 

117 Preferred % Preferred Stock {Line 113/115) 0% 

118 Common % Common Stock (Line 114/115) 0% 

119 Debt Cost Total long Term Debt (Line 101/112) 0.0000 

120 Preferred Cost Preferred Stock (Line 102/113) 0,0000 

121 Common Cost (Note I) Common Stock Fixed plus 100 Basis pts 0.1230 

122 Weighted Cost of Debt Total long Term Debt (WCl TO) 0.0000 

123 Cost of Preferred Preferred Stock 

124 

125 Rate 

126 Investment Return = Rate Base' Rate of Return Line 62 * 125 0 

Composite Income Taxes (Note H) 

127 

128 

129 

130 

131 

Income 



SIT=State Income Tax Rate or Composite 

p = percent offederal income tax deductible for state purposes 

T 

T"'1 - {[(1 - SIT) • (1 - FIT)) I (1 - SIT * FIT * p»)= 

T/(1-T) 

0.00% 

0,00% 

0.00% 

0.00% 

0.00% 

132 

133 

134 

135 




p266.8f 

o 

1/(1-T) 

1/(1 - Line 128) 

100.00% 


(Line 18) 

00000% 

ITC Adjustment Allocated to Transmission (Notel) (Line 132 * 133 *134) o 

136 Income Tax Component = CIT=(T/1-T) * Investment Return * (1-(WCl TD/R» = o 

137 Total Income Taxes o


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Exhibit No. SCE-l 0 


Page 20 of 20 


Attachment 8 - Company Exhibit - Securitization & Non-Interest Bearing Debt Workpaper 

Line # 

100 


Less LTO Interest on Securitization Bonds o 

110 

111 




o 

See FM1 p256.1, line 16 notes 


See long-Term Debt Attachment 8-1




EXHIBIT NO. SCE-ll 

FORMULA RATE (POPULATED SHEETS)


Exhibit No. seE·" 

AHachmentH·2 

Page 1 of 20 

Appendix 

A 

20gS 

V•• ow .. haded cel" ue inpule,,11e. 

~... '" 

Wag .. & S.luy Allocation Facto, 

Transmission Wall"5 Expm.e 

p35421b 

5,255,010 

Total Wage. E"Jl'mu 

p3S4_28b 

141,454,036 

31,670,065 

l .... A&GWa .Ex ..,sa 

354.27b 

Total ILine2-3) 109,793,973 

w .... & Sal. Alloc.lDr ".7882'\\. 

PlantAlloc.ldion FaclDlS 

EI"ctricPlanlin SelVic" (Note BI p207.104g 

Common Plan!ln Sa""ce Line 24 

EleenG 

Total Plant In Se",c," (Sum L.,es 6 & 7) 

7,495.204.534 

2~,7S6.562 

AcclJ"llulaled Dep"'Ciation Electric Plant 

(Note A) 

2,583,2n,956 

AtIlichment 5 

AtlBchmenl5 

Accumulal>d Olhe' Utility Plant Amorti ... tion E"ctnc Only 

(Note A) 

54,712.145 

AttachmentS 

I\ccumwl."d Corrmon Depreciation· Electric Only 

(NOleA) 

16,100,040 

lQ,BSO,83g 

Accumulalod Corrrnon OIher Utility PlanlAmort • EI&etric Only 

AttachmentS 

(Nole A) 

13 TOI.ilIAccumu .. ted o..p,,"ciation (Sum Lnes Q to 12) 2.734.021,eS3 

14 NelPlant 5.016,Qe9.113 

15 Tranomissio~ Gross Planl 

IS Gro .. PlonIAliocak>, 

Li~e 28 

Line ISIS 

762,756.419 

10.0V88% 

17 Tranomission Nol Planl 

16 N.IPlonlAliocalor 

545,164,955 

10.8884% 

Plant In Service 

Transmission PIo~1In seNio" 

(Note B) 

p207.58g 

For True up only- remove New Tran$mi$sionPlantAddition$ fOr Currenl CaleooarYear 

For True Up Only Attachment6 

New Transmission Plant Addi~onslof Current Calendar Year [weOghted bymDnth$i~ .erl'ice) 

(Note B) 

Attachmenl6 

TobO T",nsmiosion Plant In S..... ic. [line 19-20+ 21) 

746.471.076 

11.610.016 

Only 

General & Inta~gible Plonl- Electric 

Common Planl- Electric Only 

(NotesA&B) 

(Note.A& Bl 

p205.5(l & p207.QQ.g 

p356.2 

254,326.4~5 

25S,78M62 

Total Ge


Exhib' No. SeE·lt 

AtlaohmentH-2 

Page 20120 

ConstNcllonWork .. P,og ... (CWIP) 

CWIP (weighted by monlhsexpeoted to b .. placed n , .. "';ce) !Note DJ AtlBchmenl6 

Accu ..... I.ollod O.Io,,,,d Income Taus 

41 ADITneioiFASB106and 109 

42 Accu ..... I.lIod D..,..."d Income TaxuAliocalod To T,an""I8 .. lon 

Attachment1 

(Lina 41) 

-68,168,258 

_68,168,2\18 

(Note C) 

p214 

P"'p"yme ... 

Prep')menlS Labor Re&led IAccoCllt 165) 

(NoleA) 

Attachment5 

32,816,561 

Pre P' )fTlenls _ Plant Related (Acoount 165) 

(NoleA) 

Attachment5 

8,944,545 

Wage & Salary Allce.lon 

Facbr 

ILine 5) 

4.7862% 


Line 18 

108664% 

ILine 44' 46) + (Line 45' 47) 

2,542,6« 

M~teria. and Supples 

Undistributed Sbreg Exp 

Wa 8 & Sala AlloeolonFoob' 

To"'l Tr.n"",ission IIlloca ..... 

Tran"",ission Mal Tran ..mlesDn (line 81 • 82) 

(Line 70) 

4,301.Q41 

Attachment5 

(Line 79 + 80) 4,301,941" 

Line 16 

108664% 

487,487 

(line 66+ 75 + 78 + 83! 21,208,238


Exhib. No_ SeE-j t 

AttachmenjH·2 

Pa~e30120 

O.preci.olion EXpenu 

T",nsmlas"n D.p"'~ialionExp.n.. (Note NI p3367b tG.202.641 

General FlantDap",oiation - Electric Only 

(Note A and NI Attachment5 

4,027,705 

5,194,932 

Intang,blePlantAmortiz.abon· Electric Only 

AttachmentS 

(No[eA) 

Total 

W. 

9.222,637 

4.7BB2% 

e & Sola Allooaion Facbr Line 5 

(Line 88· e9) 441,413 

Common Plant Depreoiation. Electric Only 

(Note Aand N) AttachmentS 

AttachmentS 

Common PlanlAmortizalion' Elect,ic Only 

(Note Al 

Total 

w. e & Sala AJlocaian Faclor Line 5 

Common O.p",eIaHon· Elocllic: Only Alloeatod 10 r ... n..mlsslon 

8,420,312 

5,899,938 

14,320,250 

47662% 

96 Total T"'nsmir..ionO&pnoeiotion &Amortiudon 17,3211,482 

97 Tau.OIh.rthanlnco""T~x .. Attachment2 12.144:;40 

98 Total lues Otha'ihan Income 12.144,540 

Lung r.""lnl&"",' 

long 

Term tnte",.t 

Leo> LTD Interest on Secwitization Bond. (Note 0) 

p117.620 hrou9h 66e 

Attaehment 8 

139,703,215 

o 

Long 1.""lnl& ......t (Line 99· 100) 13e.703,215 

102 P",farntdORridends entBrpo ..ti"" ptl6.2ge 7,236,154 

COllYrlonStock 

Proprietary Capital 

p112,16c 

Less Prefer.,d Stock (Acc!.204) 

enter negau.e (line 113) 

Plus Secuitization Adju.tment 

Attachment8 

Less Aocount216, 1 enterne au.e 

112.12c 

COllYrlun Stock (Sum Lneo 103 to 106) 

2,817 .451,757 

·113,758,600 

Capltolization 

LongTenn Debt p112. 18, hrough 23e 2,822,511,007 

Leu Reacquired Debt 

less 

Non·iniore$t beannll debt 


{Note 0) 

(Note 0) 

enter neg.u.e 

enter negatwe 

enterneaati.te 

p112.1Qc 

AttachmentS 

Attachment8 

.33.445,()(I0 

o 

TolBl Long Tenn Debt (Sum Line. 108 to 111) 2.789,066,007 


Common Stock 

p112.3c 

Line 107 

113,758.800 

2,703,692,957 

Total C~pitalizaUon (Sum L"es112 to 114) 5,806,517,764 

". 

Oebt% 

m Preferred % 

,,. 

Common% 

Total Long Tenn Debt 

P",ferred Stoel< 

Common Sloe. 

(Line 1121115) 

(Line 1131 115) 

(Line 1141 115) 

49.7469% 

2.0200% 

48.2241% 

'" 

'" 

Debt Cost 

,


E,hib. No. seE·" 

AHachm~ntH·2 

Page4of20 

Incomo Tu Ratas 

FIT~Fede .. llnCOm& Ta' R.i'> 35.00% 

811=8101& Income Tax Rate or Composite (NOieH) 

, 

Till-TI 

(percent of fed""" income tax dedu:tible for .Iale purpo ... ) 

T~l - (lit. SIT)' (1 _ FIT)] I (1 - SIT' FIT' pI) ~ 

500% 

P",StateTaxCode 

000% 

3825% 

61.Q4% 

ITC Adjuslrnenl (Note HI 

Amortized InvestmentTax Credit p2668f 

enler neg.we -4.806,400 

16194% 

1111-T) 1/(1· Une 128) 

10Blj~4% 

Net PlantAlfocotion Facbr Line IS 

ITC A,djus""""l Allocated to T'on.mi.sion {Line tn"133' 134) -845,803 

CIT~(T'l.T)· Inv"SlmenlRetum' (l-(WCL TD.R)) ~ {Line 131" 126' IHln1125))] 16,839.142 

137 TotollncomeT.,. ... 

'" 

"" '" '" 

'" 

AdJus"'.ntto Remove Ro""nu. Requirement. A.. "cJolltdwith hcluded l.an"miosion Facllti.,. 

Tra~,mi,.ionPI.~t 

Less Excluded Tran;mi,.ion Facilti". (Nole L\ 

I~cluded Tranoni .. ion F!ociliti@, 

Inclusion Ra"O 

Summary and Adjuatm.ntby Inclusion Ratio 

Net Property, Plant& Equipmenl 

'" 

Ad'uslmentlo Rate Base 

'" "" 

W"" 

H" 

H. 

,00 

'" 

'" 

"" 

(Line22+40+43) 

Altilchmenl5 

(Line 139,140) 

(Lin@1411139) 

(Line 38 '142) 

Line6l '142 

106,003,442 

758,341,152 

47,316.5CO 

711,022,591 

n 7603% 

511,146,048 

.54,233,124 

Rate Base (Lin@62"142) 456.914,924 

0'" 

Depreciation 8 Amortizabon 

Taxes ether tr..n tncome 

Inv@stmentRetum 

l~comeTaxes 

Less: Interest on N@\Wor1

"o 

o 

'" .... 

"ẉ ... 

I 

o 

W 

-J 

;:J 

~ 

:g 

D" 0 Z 'i::.;;-,"~·9'f .~ .... ~" "g~ 

ilg~~i~~[i~~~~~~~~~.'5~l~~~ 

'~lli:li~I~~~il~~~~lii-~~ 


ExhibitNo. seE-II 


Page 6 of 20 

South Carolina Electric & Gas Company (SCEGI 

ADlT- 282 

ADlT·283 

ADlT-190 

Subtotal 



All Transmission 

ADiT Allocated to Transmission 

Attachment -1 - Accumulated Deferred -Income Taxes (AOIT) Worksheet 

On~ 


Plant 

Labor 

~ 

(672,334,120) (672,334.720) 

(11,994,424) (120,197,576) (132,192,000) 

24,062,485 69,081,000 113.143,485 

(660,266.659) (31.116.576) (691,383,235) 

4.7862% 

10,0988% 

100% 

(66.67B,952) (1.489,316) {68.168.268} 

Column C AOIT ~ems (below) relille only to Non·[1ecIric: Operations (e.g. Gas) OR Production OR Items NOT included in Ihe AOIT calculation above 

Column C amoullltotais 50.553,670 

Check total- Agrees to Recon. (Attachment 1-2) (640.829.565)


Exhibit No. SCE-It 


Page 7 of 20 

ADlT-190 

Attachment 1• Accumulated Deferred Income Taxes (ADIT) Worksheet 

A B C 

Production 

Or Other 

Irul 

IN"'", I >0079.570 ",07"" 

D 

Only 

TransmissIon 

E F G 

POnt 

"""'" """'" """'" 

, , 

p"' .. P'''''"'''" , . 

p,Id., ,,,a",,, 

, 125,800 125,800 

;;,;"', ,"0","", ,.,,",. "",,","p; p~,; 

""" 

IN~.' R"","" 2,805,000 2,8OS,000 paid. 

"'a"" 

~::;~;~::" w~,' ","~"","o,? "ruo,","" I 

Is>.I , ,C,," 18842,600 18.842,600 

, 

'dlff"~'~,:,,:~~~?~P~ , 

, 

, 

" ""' "'mp"", I"" I "F"lAmil 

1.437,500 1,437500 

. 000" 

'""" 

5,219,885 5,219,885 "Id· ... ,.: ~'~":~," "pe",~, 

"" 

, 

I.s , C,IegP~" ,,," 

, ..il!ax~ , 

,00 ' 

"" '" 

1,031,600 1,031,600 

I I mEG 1,7'6,500 1,766,500 

_ 

..d 

' ,ocr"", 

=::,:'!:::::p~:"".""-~~: 

, 

~ written ott 

relates to Retail 

:k esb~ate;l in I II j """"''', ,."" 

I ,BENE'''EG 44,742,800 '-,42,BOO ~~i~kesn~ate; i , ~:."-""",M, 

1WOOO 

0~5'5B '",6,000 '.0".000 

acalJld ard expensed, ta", deduction when 

I sin ill' . Offset is i . 

"ORM I 18''',200 18,""00 




Page 8 of 20 

AD/T- 282 

''''",'' 

, 

Attachment 1- Accumulated Deferred Income Taxes (ADlT) WorlI'sheat 

A B C 

--- - 

D 

E F G 

Production 

Dnly 

Or Other Transmission Plant 

To'" R",to. R",to' 

, om""",,~~~~g.rrom 1 

II 

'''',,,' - N" , 0 

"'" "'."" ,~o,"'.'" '",ooo~:,.;~d;;, 

'W"~, 

, 

,~",'"' rrom1 

, I,""""" . , ". 

5"'" 

, - N, 0 . :;':::;::; p;, "''I",' ~:,:"' 

i,. 

"'~.".,. ", 

~,,&S"" - D",,- 53.164,400 53.164.400 ' ~"':'; p;"""",,, "'y. 

, . ~m~,,~,o", 

'''',,,' & 5.. " ."i, - D,m 8,244,200 8,244.200 ,"""",,::;':,::~ p"","",,,' :,~' 

"',,,' & 5.." R~~"h - D, 

'''',,,' R"woh Pmj~I' (121 ,BOO) (121.800) 

I~.:'.'.:_~;i 

'W"~, 

",'" ,,',. 

- '."e' 10 1II 

'od,," & 5.... , , , 12131108 11.101,600 11.101,600 

I~"'" ''''",''''''', """""' - '.;';;;-~, II 

'''',,,' & 5" .. i ,N"c .. , 12elm8 (497.50ot (497,500 I~~:'" 

, ,"""""' ',::" to p,,,,,",,,,, 

""",,' ,so, , ,oih', '2I31/Q' "''',000< b.:_~"' , -'.""'101 II 

S"'m G",,,"," R~M' r.• '''""0. 0 

l~~:'" 'od",""'''' 

- ,.,"'" 10 p,,,,,,,,,, 

, 

D." R< ,,' Cool 0 0 I~.:'.'.:_~"' i i 

II 

, 

~mi~i'" AII,w,",,, I~" '"'od""",,,, . raaled to Production 

2.701,200 2,701.200 

1;",;- 

l::,'rty"""'i":'::,:,:'~ , 

I " p,,,,,",,,, 

, 

SC'C II 0 

I"" IG,oo,", , 

, '" '~S :;,;::;"",',,'''i' 

AD'T'" EI~ Pit 'AS. 109 co"~ 

;.-; ,ta)(ablewhenr:Co;~~ lU~_P~~~:'~r~:iS 

, ; Pit 'AS. 109 "',0",,000< '" "',000< 1m,'", 

~ 

Ins!rUctionslor Account 282: 

~ 

- 

,. ADIT items related only to Non·Electric Operations (e.g., Gas, Waw, Sewer) or Production are directly assigned to Column A 

2. ADIT ~erns related only to TransmiSsion are directly assigned to Column 8 

1. ADIT items related Plant and not in Columns A & B are diroctly assigned to Column C 

4. ADIT items relaled to labor and not 'In Columns A & 8 are diroctly assi!Jled to Column D 

5. Deferred income tal'eS arise when ttems are included in taJcable income in different periods than they are included in rates therefore, iflhe item giving rise to the ADIT is nol 

included inthe formula. the associated ADIT amount shall be excluded


Exhibit No. SCE-l1 


Page 9 of 20 

Attachment 1. Accumulated Deferred Income Taxes (ADlT) Worlfsheet 

ADlT-283 

Litillatic 

A 

B C D E F 

Production 

Dnly 

Or Other Transmission Plant La"'" 

"""' 

~.R~_ ""'". "",,,. 

46.800 46.ADO 

'.~' 

".~"oo, 

.'''' 

".~' " 

I~~",."'~M completely for books. Capitalized & depreciated 

I~;;;~-,;"~ R"",d \0 I "I,,,P,,,,,"O"001, 

G 

~Im"" 

'"'' 

.Me,00 

t.'" 

o o 

I::'~. ""~:.",pe",~ 

(1.038.000( 

i Ii ~Io 

1~'":'~:~,'1''' . 

l i~i~~~~~~'''~C!:~''''':J~';'~r decrease 

"'''" 

payment amount taxincome and expense based Q(1 

, books~ Arid to eliminate book amortization on 

refinancing the lease, which was deducted 

~ears ~o.w~'2. incurred lor tax. Portions of the Palm center 

6MOO """ , . 

,w:,~~~;,;,;; 

'·'1 

I Ii" ~toratel 

'"'""'" ;"'. . '.",d . 

i : 

10'0> 

, book 

INUSTART 

lOPE. 

14,000 

14.616.000 

14,000 

" to, 

~ U~ed for ratemaklng 

. "wIt~ 

. Offset is in 190 acco ..mtso 

"".700 

17."00' 

Ivcs C~I' R",A;~I 

(1.125.100) 

(32~ 

,\0, "ot dobllb,I",,, 

Inslruclions 

for Acco1..n128J: 

1 ADlT items related Drily 10 Non-Electric Operations (e.g., Gas, Water. Sewer) or Production are directly assigned to Column A 

2. ADrr items related only to Transmission are directly assigned 10 Column B 

3 AOIT items related PIaI1l and not i!1 Colurms A & B are directly assigned 10 Columo C 

4. ADIT items related to labor and not in Colurnrl5 A & B are directly assi~ed to Column 0 

S. Deferred income taxes arise when ilems are included in IalUlble income in differem periods than they are included in rales therefore, ifthe item giving rise 10 the ADn is nol 

ir.cluded in the lonnula.1he associated Aon amoun!: shall be excluded




Page 10 of 20 


Attachment 2 - Taxes Other Than Income Taxes Worksheet 

Other Taxes 

Page 263 

Col (i) 

Allocator 

Allocated 

Amount 

Plant Related 

Gross Plant AI/ocator 

County Property 

Municipal Property 

p263.18.i 

p263.19.i 

99,802,289 

5,198,967 

Total Plant Related 

105,001 ,256 

10.0988% 10,603,858 

Labor Related 


FUTA 

FICA 

SUTA 

p263.3.i 

p263.4.i 

p263.13.i 

130,647 

11,321,960 

212,301 

Total Labor 

Related 

11,664,908 

4.7862% 558,311 

Other Included 


License 

p263.10.i 

9,727,608 

Total Other Included 

9,727,608 

10.0988% 982,371 

Tota/lncluded 

12,144,540 

Currently 

Excluded 

Electric 

Income 

Income 

Generation 

Tax - Federal 

Tax - State 

p263.12.i 

p263.2.i 

p263.9.i 

6,894,944 

35,961,100 

3,399,400 

Total as reported 

on p. 263(i) 

172,649,216


Exhibit No.SCE-11 


Page 11 of 20 



1 4470004 - Transmission Short-Term (Note 1) 


3 4470004 - ST Ancillary Services Revenue (Note 1) 

4 4470006 - l T Ancillary Services Revenue (Note 1) 


Attachment 

3 • Revenue Credit Workpaper 

Total Account 

$ 657,746 

7,036,547 

103.316 

1,531,321 

(Sum Lines 1-5) $ 9,328.930 



Amount 

$ 657,746 

19,649 

185,860 

$ 863,255 



7 land Rental Revenue - Generation Property 








15 Total Rent Revenues 

$ 11,821,787 

278,227 

5,723,989 

103,640 

3,600,240 

221.362 

366,496 

5,961 

184,807 

(Sum Lines 7-9) $ 22,306,509 

$ 565,820 

273,964 

172,316 

221,362 

8,845 

$ 1,242,308 


16 Transmission at Electricity for Others - Form 1, pg 330 less Network Customers & Woodland Hiiis (Note 1 ) $ 

17 Ancillary 1 & 2 Charges - Form 1. pg. 328, column m/7 less Network Customers (Note 1) 

18 Transmission of Electricity for Others - Network Customers 

19 Anciiiary 1 & 2 Charges - Network Customers (Note 1) 

20 Woodland Hills Contract(Note 1) 

21 Total Other Electric Revenues (Sum Lines 11-13) $ 

5,576,346 

843,433 

316,974 

24,513 

75,000 

6,836,266 

$ 5,576,346 

170,761 

4,892 

75,000 

$ 5,826.999 

22 Totals (Line 5 + 15 + 21) $ 38,471,705 

$ 7,932,562 

Notes: 


which the cost of the service is recovered under this formula, except as speCifically provided 

for elsewhere in this Attachment or elsewhere in the formula will be included as a revenue 

credit or included in the peak on line 170 of Appendix A. Types of revenue included as a 




assets: (1) right-at-way leases and leases for space on transmission facilities for 

telecommunications; (2) transmission tower licenses for wireless antennas; (3) right-of-way 


(Including a portable oil degasification process and schedul"lng software); and (5) 


high-voltage substation maintenance, safety training. transformer oil testing, and circuit 



to the revenue 

requirement. 



the Directly Assigned Facility Charges are not included in the Rates, the associated 

revenues are not included in the Rates.




Page 12 of 20 

South Carolina 

Electric & Gas Company (SCEG) 

Attachment 4 - 100 Basis Point Increase in ROE 

Net Plant New Investment Incenitive@ 100 Basis Poinis 

A 


New Investment ROE Incentive and Income Taxes 55,384,834 

B Net Plant New Investment Incenitive@100BasisPoints 1.00% 

Return 

Calculation 

,.5 Rate Base (line 62 * 142) 456,914,924 


99 long Term Interest p117.62c through 66e 139,703,215 

101 Long Term Interest (Line 99 -100) 139,703,215 

102 Preferred Dividends enter positive p118.29c 7,236,154 

Common Siock 

103 Proprietary Capital p112.16c 2,817,451,757 

10. Less Preferred Stock (Acct. 204) enter negative (Line 113) -113,758,800 

106 Less Account 216_1 enter negative E!112.12c 0 

107 Common Stock (Sum Lines 103 to 106) 2,703,692.957 


108 Long Term Debt pl12.18c through 23c 2,822.511.007 

109 Less Reacquired Debt enter negative pl12.19c 0 

110 Less Non-interest bearing debt enter negative Attachment 8 -33.445.000 

112 Total Long Term Debt (Sum Lines 108 to 111) 2.789.066.007 

113 Preferred Stock p112.3c 113.758.800 

114 Common Stock {Line 107! 2.703,692.957 

115 Total Capitalization (Sum Lines 11210 114) 5.606,517.764 

116 Debt % Total Long Term Debt (Line112/115) 50% 

117 Preferred % Preferred Stock (Line113/115) 2% 

118 Common % Common Stock (Line114/115) 48% 

119 Debt Cost Total Long Term Debt (Line 101/112) 0.0501 

120 Preferred Cost Preferred Stock (Line 1021 113) 0.0636 

121 Common Cost (Note I) Common Stock Fixed plus 100 Basis pts 0.1230 

122 Weighted Cost of Debt Total Long Term Debt (WCL TO) (Linel16*119) 0.0249 

123 Weighted Cost of Preferred Preferred Stock (Linel17*120) 0_0013 

12. Weighted Cost of Common Common Stock (Line 118 * 121! 0.0593 

125 Rate of Return ( R ) (Sum Lines 122 to 124) 0.0855 

126 Investment Return '" Rate Base * Rate of Return ,Line 62 * 1251 39,077,337 

Composite Income Taxes (Nole H) 

127 

128 

129 

130 

131 

Income 



8lT=8tate Income Tax Rate or Composite 

p::: percent of federal income tax deductible for state purposes 

T T=l - {[(l - 8IT)· (1 - FIT)) 1 (1 - SIT * FIT * pI} = 

TI (l-T) 

35.00% 

5.00% 

0_00% 

38.25% 

61_94% 

132 

133 

13. 

135 




p266_8f 

-4,806.400 

1/(1-T) 

1/(1 - Line 128) 

161.94% 


(Line 18) 

10.8664% 

ITC Adjustment Allocated to Transmission (Notel) (Line 132 *133 * 134) -845.803 

136 Income Tax Component = CIT=(T/l-T) * Investment Return' (l-(WCL TO/R)) '" 17.153,301 

137 Total Income Taxes 16,307,497


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Page 20 of 20 


Attachment B - Company Exhibit - Securitization & Non-Interest Bearing Debt Workpaper 

Line # 

100 


less LTD Interest on Securitization Bonds 

o 

110 

111 




$ 

(33,445,000) See FM1 p256.1, line 16 notes 

o 


See Long-Term Debt Attachment 8-1





STATEMENTS BG AND BH

Stat.",ent BG Propwed Retes 


Statement BG Proposed Rates & Statement BH Current Rates 

Revenues by Network and Point to Point Transmission Service Customers 

For the 12 Months Ended December 31,2008 

Exhibit 

No. SCE-12 

Page 1 of2 

"o 

o 

'" .... 

"W 

.... 

I 

o 

W 

-J 

;:J 

~ 

:g 

'" 

~ 

NMwPrk 

Customers 

Customer 

Name 

Central Electric Power Cooperative 

SCE&G lOr City of Greenwood 

SCE&G for Orangeburg DPU 

SCE&G tor Town of Winnsboro 

New Horizon Electric Cooperative 

Soutl1eastem Power Administration 

Total Network Revenue 

Lona Te!lIlPolnt to Point lLLPtP) Customm 

Customer 

Name 

$ 58,907 $ 54,230 $ 40,957 $ 29,676 $ 37,347 $ 44,223 $ 46,983 $ 50,097 $ 43,295 $ 41.738 $ 53,962 $ 54,803 $ 556,218 

86,320 84,931 70,669 67,051 92,436 119,849 120,379 127,029 111,698 72,911 76,818 87,971 1,118,061 

252,798 258,243 221,439 179,277 210,006 299,332 288,137 307,781 278,338 219,011 202.345 251,864 2,968,571 

19,332 22,504 16,759 13.9oa 17,682 26,173 23,192 24,451 22,099 14,517 16,092 17,917 234,625 

33,096 31,804 27,846 18,141 31,154 28,966 28,240 28,993 22,138 23,970 31,242 33,291 336,879 

32,121 32121 32121 32,121 32121 32121 32121 32,121 32121 32121 32,121 32121 385,449 

482,573 $ 483,832 $ 409,790 $ 338,171 $ 420.745 $ 550,664 $ 539,052 $ 570,472 $ 509,688 $ 404,268 $ 412,580 $ 477,967 $ 5,599,802 

~ 

~. 

n 

~. 

~ 

.... 

.... 

-.... " 

" 

-.... '" 

"o 

o 

'" 

SCE&G Power Mktg {for NCEMC) 

SCE&G Power Mktg 

437,851 $ 437,851 $ 437,851 $ 437,851 $ 437,851 

350,281 350,281 350,281 350,281 3SO,281 

437,851 

350,281 

437,851 437,851 437,851 $ 437,851 437,851 $ 437,851 

5.254,210 

2,101,684 

Long_term Point to Point Revenue 

$ 788,132 $ 788,132 $ 788.132 $ 788,132 $ 788,132 $ 788.132 $ 437.851 437,851 437,851 437,851 437,851 437,851 $ 7,355,894 

Total Network and LT PIP Revenue 

$ 1,270,704 $ 1271,964 $1197,921 $ 1,126,303 $ 1.208,876 $ 1338796 $ 976,903 $ 1,008.323 $ 947,539 $ 842,119 $ 850,431 $ 915,818 $ 12,955,697 

Statement BH Cummt Rates 

Network 

~ers 

Customer 

Name 

Central Electric Power Cooperative 

SCE&G fOr City of Greenwood 

Orangaburg 

DPU 

SCE&G for Town of Winnsboro 

New Horizon Electric Cooperative 

Southeastern Power Administration 

20,032 $ 19,861 $ 19,542 $ 19,855 $ 20,042 $ 19,910 $ 20,039 $ 20,004 $ 20,156 $ 20,604 $ 21,086 $ 20,875 

41,875 41,415 41,359 40,820 40,642 40,433 41,224 41,425 41,649 41,163 41.213 41,386 

114,227 113,395 112,830 111,854 112.158 111,603 113,597 113,552 113,330 113,245 110,899 110,542 

11,028 10,882 10,771 10,528 10,273 10,099 9,812 9,551 9,337 9,107 8,907 8,700 

11,417 11,390 11,380 11,750 11,749 11,799 12,160 12,218 12,218 12,559 12,649 12,652 

14,236 14,161 14,103 14,086 14,173 14,052 14,688 _J4,690 14,692 14,865 __ 14,643 ~644 

242,006 

494,204 

1,351,341 

118,996 

143,941 

173,033 

Total Network Revenue 

$ 212,616 $ 211,105 $ 209,985 $ 208,692 $ 209,03] $ 207,898 -.L.l.l1.518 $ 211,459 $ 211~ 211,543 $ 209,396 $ 208,899 2,523,521 

Lona Term_Point to Point {~J Customers 

Customer 

Name 

SCE&G 

SCE&G 

Power Mktg {for NCEMC) 

Power Mktg 

287,500 $ 287,500 $ 287,500 $ 287,500 $ 287,500 $ 287,500 $ 287,500 $ 287,SOO $ 287.500 $ 287,500 $ 287,500 $ 287,500 $ 3,4SO,OOO 

230,000 230,000 2:30,000 230,000 230,00_0__ 230,000 1,380,000 

Long.term Point to Point Revenue 

517,500 L_517,5OO $ 517,500_ $ 517~517 SOO $ 517,SOO $ 287,500 $ _287,500 $ 287~09 $ 287,500_~ 287,500 $ ~?,500 $ 4,830,000 

Total Network and LT PIP Revenue 

$ 730116 $ 728805 $ 727485 $ 726.192 $ 726537 $ 725398 $ 499018 $ 498.950 $ 498,881 $ 499,043 $ 496,896 $ 496,399 $ 7,353,521

Network Customers 

Customer 

Name 


Statement BG 

Coincident Peak by Network Customer and Reservations by Point to Point Customer 

For the 12 Months Ended December 31, 2008 

Exhibit seE - 12 

Page 2 of 2 

Central Electric Power Cooperative 33.6340 30.9640 23.3850 16.9440 21.3240 25.2500 26.8260 28.6040 24.7200 23.8310 30.8110 31.2910 317.5840 

SCE&G for City of Greenwood 49.2860 48.4930 40.3500 38.2840 52.7780 68.4300 68.7330 72.5300 63.7760 41.6300 43.8610 50.2290 638.3800 

Orangeburg DPU 144.3400 147.4490 126.4350 102.3620 119.9070 170.9100 164.5180 175.7340 158.9230 125.0490 115.5330 143.8070 1.694.9670 

SCE&G for Town of Winnsboro 11.0380 12.8490 9.5690 7.9400 10.0960 14.9440 13.2420 13.9610 12.6180 8.2890 9.1880 10.2300 133.9640 

New Horizon Electric Cooperative 18.8970 18.1590 15.8990 9.2160 17.7880 16.5390 16.1240 16.5540 12.6400 13.6860 17.8380 19.0080 192.3480 

Southeastern Power Administration 18.3400 18.3400 18.3400 18.3400 18.3400 18.3400 18.3400 18.3400 18.3400 18.3400 18.3400 18.3400 220.0800 

Total Network Usage 275.5350 276.2540 233.9780 193.0860 240.2330 314.4130 307.7830 325.7230 291.0170 230.8250 235.5710 272.9050 3,197.3230 

Long T!rm Point to Point ILT ~Pl 

Customer 

Name 

C!!!!12m!r! 

"o 

o 

'" .... 

"w 

.... 

I 

o 

W 

-J 

;:J 

~ 

:g 

'" 

~ 

~ 

n 

~ ~.... 

.... 

-.... " 

" 

-.... 

'" 

"o 

o 

'" 

SCE&G Power Mktg (for NCEMC) 250.0000 250.0000 250.0000 250.0000 250.0000 250.0000 250.0000 250.0000 250.0000 250.0000 250.0000 250.0000 3.000.0000 

SCE&G Power Mktg 200.0000 200.0000 200.0000 200.0000 200.0000 200.0000 1.200.0000 

Total Long.term Point to Point Reservations 450.0000 450.0000 450.0000 450.0000 450.0000 450.0000 250.0000 250.0000 250.0000 250.0000 250.0000 250.0000 4.200.0000 

Total Network & LT PtP Usage and Reservations 725.5350 726.2540 683.9780 643.0860 690.2330 764.4130 557.7830 575.7230 541.0170 480.8250 485.571Q... 522.9050 7,397.3230






OF 

MICHAEL 

J. VILBERT 



EXHIBIT NO. 

SCE-13 


BEFORE THE 


South Carolina Electric & Gas Company Docket No. ERIO- -000 


MICHAEL J. VILBERT 




TABLE OF CONTENTS 

I. INTRODUCTION AND SUMMARY I 

II. COST OF CAPITAL THEORY 7 

A. THE COST OF CAPITAL AND RISK 7 

B. INVESTMENT IN THE TRANSMISSION GRID 10 

C. THE IMPACT OF CURRENT MACROECONOMIC CONDITIONS ON THE COST OF EQuITY 13 

III. THE COMMISSION'S COST OF CAPITAL METHODOLOGY 21 

A. THE PROXY GROUP 21 

I. Selection of the Proxy Group 21 

2. Credit Rating Restriction 23 

3. Characteristics ofthe Proxy Group 26 

B. THE DISCOUNTED CASH FLOW ApPROACH 27 

1. The Theoretical DCF Model 27 

2. The Commission's Preferred DCF Model 28 

C. PROXY GROUP ESTIMATES AND THE RANGE OF REASONABLENESS 30 

EXHIBIT NO. SCE-14 - APPENDIX A: RESUME 

EXHIBIT NO. SCE-15 - APPENDIX B: THE FERC METHODOLOGY: SAMPLE 

SELECTION 

AND THE DCF 

EXHIBIT NO. SCE-16 - TABLES AND WORKPAPERS


Direct Testimony of Michael J. Vilbert 


Page 1 of35 

EXHIBIT 

NO. SCE-13 

I. INTRODUCTION AND SUMMARY 

2 Qt. Please state your name and address for the record. 

3 AI. My name is Michael J. Vilbert. My business address is The Brattle Group, 44 Brattle 

4 Street, Cambridge, MA 02138, USA. 

5 Q2. Please describe your job and your educational experience. 

6 A2. I am a Principal of The Brattle Group, ("Brattle"), an economic, environmental and 

7 management consulting firm with offices in Cambridge, Washington, London, San 

8 Francisco, Brussels and Madrid. My work concentrates on financial and regulatory 

9 economics. I hold a B.S. from the U.S. Air Force Academy and a Ph.D. in finance from 

10 the Wharton School of Business at the University of Pennsylvania. 

II Q3. Please summarize the parts of your background and experience that are 

12 particularly relevant to your testimony on these matters. 

13 A3. Brattle's specialties include financial economics, regulatory economics, and the gas, 

14 water and electric industries. I have worked in the areas of cost of capital, investment 

15 

16 

risk and related matters for many industries, regulated and unregulated alike, in many 

forums. Ihave testified or filed cost of capital testimony before the Arizona Corporation 

17 Commission, the Pennsylvania Public Utility Commission, the Public Service 

18 

19 

20 

21 

Commission of West Virginia, the Public Utilities Commission of Ohio, the Tennessee 

Regulatory Authority, the Public Service Commission of Wisconsin, the South Dakota 

Utilities Commission, the California Public Utilities Commission, the Canadian National 

Energy Board, the Alberta Energy and Utilities Board, the Ontario Energy Board, and the 

22 Labrador & Newfoundland Board of Commissioners of Public Utilities. Ihave also filed 

23 testimony before this Commission. Appendix A contains more information on my 

24 professional qualifications. 

25 Q4. What is the purpose of your testimony in this proceeding? 

26 A4. South Carolina Electric & Gas ("SCE&G" or the "Company") has asked me to estimate



Docket ERJO- -000 

Page 2 of35 


the cost of equity that the Federal Energy Regulatory Commission (the "FERC" or the 

2 

3 

4 

5 

"Commission") should allow it an opportunity to earn on the equity-financed portion of 

its rate base for electric transmission assets. To answer this question, I have implemented 

the discounted cash flow ("DCF") method favored by the Commission and applied it to 

two samples of regulated electric utilities.! 

6 Q5. Are you sponsoring any exhibits? 

7 AS. Yes. I am sponsoring Exhibit No. SCE-14 to Exhibit No. SCE-16. This latter exhibit 

8 contains the tables and workpapers supporting Tables I, 2 and 4 of my direct testimony. 

9 Q6. Please summarize how you approached the task of estimating the appropriate 

10 

II 

12 

13 

14 

IS 

16 

17 

18 

19 

20 

21 

A6. 

return on equity for SCE&G's transmission assets. 

The first step is to select the appropriate sample (or proxy) group, which I did after 

review and consideration of prior Commission decisions. 

The Commission has found 

that the appropriate proxy group for use in calculating the return on equity ("ROE") using 

the DCF method is made up of companies from the region in which the utility is located? 

This is because the Commission has concluded "that being located in the same 

geographic and economic region is relevant in determining whether companies face 

similar business risks.") 

The Commission has typically relied on proxy groups drawn 

from the RTO market area in which the applicant is located,4 although the Commission 

has in some cases utilized proxy groups, beyond a single RTO market area, that include 

entities in the entire WECC. 5 

SCE&G is not a member of an RTO. Therefore, consistent 

with the WECC cases, I have selected a sample of regulated transmission owning electric 

I The cost of capital analysis presented herein is specific to the Company's transmission investment, and the 

analytical methods used here are those adopted and approved by the Commission. 

2 See, e.g., Westar Energy, Inc., 122 FERC 1161,268 at P 93 (2008) ("Westar'~; Tal/grass Transmission, LLC, 

et al., 125 FERC 1161,248, at PP 74-75 (2008) ("Tal/grass'l 

3 Startrans 10, L.L.c., 122 FERC 1161,306, at P 25 (2008) ("Startrans"); See also, Westar, 122 FERC 11 

61,268, at P 93 (to the same effect). 

4 Tal/grass, 125 FERC 1161,248. See also, Potomac-Appalachian Transmission Highline, L.L.c., 122 FERC 11 

61,188 (2008) ("PATH'); Pepco Holdings, Inc., 124 FERC 1161,176 (2008) ("Pepco"). 

5 Southern California Edison Co., 122 FERC 1161,187, at P 26 (2008) ("So Cal Edison"); Startrans, 122 FERC 

1161,306, at P 25.


Direct Testimony of Michael 1. Vilbert 

Docket ER I0-_-000 

Page 3 of35 

EXHIBIT 

NO. SCE-13 

utilities that are located in the southeastern portion of the United States, which is the 

2 

same geographic and economic region in which SCE&G is located. 

3 

4 

5 

6 

7 

8 

9 

10 

Next, I restricted the proxy group according to the Commission's guidelines articulated in 

Westar Energy, Inc., 122 FERC ~ 61,268 (2008) ("Westar"), Potomac-Appalachian 

Transmission Highline, L.L.C., 122 FERC ~ 61,188 (2008) ("PATH') and Atlantic Path 

15, LLC, 122 FERC ~ 61,135 (2008). I applied the Commission's DCF method to two 

samples (explained below) selected from the universe of regulated electric utilities that 

are located in southeastern United States. After eliminating the results of some 

companies due to reliability concerns, consistent with established Commission 

guidelines, I then determine a "range of reasonableness" for the cost of equity. 

II Q7. Please describe the two samples you use. 

12 A7. The first sample, which I call the Full Sample, consists of all regulated utility companies 

13 in the southeastern United States that meet all of the standard FERC requirements for 

14 inclusion in a sample. 6 The second sample, which I refer to as the Restricted Sample, 

15 results from eliminating companies from the Full Sample whose Standard & Poor's 

16 ("S&P") credit ratings are not within one notch of SCE&G's BBB corporate credit 

17 rating'. A "range of reasonableness" for the cost of equity was established for each 

18 sample by using the highest and lowest qualifying cost-of-equity estimates from that 

19 sample.' 

20 Q8. What are the results from the application of the Commission's preferred DCF 

6 The standard criteria are that the sample company be a publicly traded company that pays dividends, has no 

dividend cuts or substantial merger or acquisition activity over the last six months, and has an investmentgrade 

bond rating. 

7 SCE&G's corporate credit rating is based on its parent company's (SCANA Corporation) credit rating. 

SCANA's medium term, senior unsecured debt is currently rated Baa2 by Moody's and BBB by S&P (these 

are equivalent ratings). Fitch, however, currently assigns a slightly higher rating of BBB+. I use the BBB 

benchmark in my ranges since two out of the three ratings agencies have rated SCANA's debt as such, and 

this is not a substantial deviation ITom the BBB+ rating assigned by Fitch. 

8 Sample company cost-of-equity estimates are included in the results if the sample company's cost-of-equity 

estimate exceeds its estimated market cost of debt by at least 100 basis points (bps), and the cost-of-equity 

estimate does not rely on an estimated growth in earnings per share that exceeds 13.3 percent.




Page 4 of35 


2 A8. 

3 

4 

5 

6 

methodology? 

When applied to the Full Sample, the Commission's preferred DCF methodology results 

in a "range of reasonableness" for the cost of equity of between 7.72 and 16.16 percent, 

with a median of 11.04 percent and a mid-point of 11.94 percent. The range of 

reasonableness for the sample restricted by bond rating becomes 8.76 to 16.16 percent, 

with the median unchanged at 11.04 percent and a higher midpoint of 12.46 percent. 

7 Q9. Does SCE&G recover the revenue requirement for its transmission assets through a 

8 formula rate? 

9 A9. No, not at this time. However, in this proceeding, the Company is proposing a formula 

10 

II 

rate for recovery of its transmission revenue requirement. 

the testimony of company witness, Mr. Alan C. Heina. 

This proposal is discussed in 

12 QI0. 

13 

14 AIO. 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

Are there other ways to estimate the cost of capital for a FERC regulated electric 

transmission company? 

Certainly. There are many different approaches, and I have used other methods in other 

proceedings. Moreover, the determination of the cost of capital requires the application 

of informed judgment as well as science. Of the several ways to estimate the cost of 

capital, I believe a "risk positioning" method is generally superior; but in the past the 

Commission has consistently not relied upon alternative estimation methods. In other 

testimony, I have been critical of some of the assumptions underlying the DCF method, 

and the FERC DCF method does not directly consider differences in financial risk among 

the sample companies or between the sample companies and the target company. While I 

believe that the Commission should not mechanically reject other methods of estimating 

the cost of capital, I also believe that whatever method the Commission ultimately 

chooses to use, the method should be consistent from proceeding to proceeding. 

25 Qll. Why did you not implement alternative approaches in connection with this 

26 proceeding'? 

27 A II. The FERC prescribes the DCF method and has used it in many previous cases to




Page 5 of35 

EXHIBIT 

NO_ SCE-13 

establish the allowed return on common equity for other electric transmission companies. 

2 

3 

4 

5 

6 

7 

It would be unfair and would increase regulatory uncertainty if the Commission were to 

apply its current DCF procedure in one proceeding and ignore it in another for similarly 

situated electric transmission companies. Selectively applying precedent potentially 

results in arbitrary estimates of the cost of capital and may result in an unjust and 

unreasonable allowed rate of return. I have, therefore, implemented the FERC's DCF 

method in a manner that is consistent with recent Commission decisions on the allowed 

8 

return on equity for transmission 

assets. 

9 Q12. Does the data in your cost of capital analysis reflect the effect of the current 

10 economic conditions on the cost of capital? 

II A12. The data I rely on is through September 30, 2009, which is after the recent period of 

12 

13 

14 

IS 

16 

17 

18 

19 

20 

21 

22 

increased volatility in the U.S. capital markets due to the recent financial crisis, along 

with the beginnings of recovery - at least to a certain extent. As such, my data does 

reflect the effect of current economic conditions. However, as a general principal, simple 

DCF models cannot reliably measure the rapid changes in the cost of capital which 

happen during volatile times. This is because the DCF model is based on the assumption 

of stable market conditions. With smaller samples, this reliability issue can have a 

substantial impact on the reliability of sample statistics, such as the midpoint, median, or 

mean. As I discuss below, current cost of capital estimates for the sample demonstrate 

this characteristic, with a substantial divergence between midpoint and median. The 

indication is that the median is likely to be a conservative estimate of the cost of capital at 

this time. 

23 Q13. Are there any other specific factors that should be considered in determining a fair 

24 return for SCE&G? 

25 A13. Yes. SCE&G has committed to an extensive capital investment program including new 

26 

transmission lines that will be primarily devoted to connecting two new nuclear 

27 

generating units that are still in its planning and development stages. 9 This creates a 

9 SCE&G is building two nuclear units at its current Summer Station generating plant. Each unit is rated at 1,117




Page 6 of35 

EXHIBIT NO_SCE-13 

substantial additional layer of risk relative to a company with a less extensive capital 

2 

3 

4 

5 

6 

investment program. The record of the nuclear program in this country has been mixed. 

Regulatory hurdles create the potential for budgetary over-runs and delays in nuclear 

construction, which may directly affect the ability of SCE&G to recover costs on the 

transmission line. Lastly, the lag in cost recovery during construction will place a strain 

on SCE&G's credit metrics, which will put upward pressure on SCE&G's cost of debt. 10 

7 Q14_ Considering all of the evidence, what is your recommended return on equity for 

8 SCE&G's transmission assets? 

9 A 14. I recommend an 11.5 percent ROE at this time. The median of the Restricted Sample 

10 estimates is 11.04 percent, and as I noted earlier, this number should be viewed as 

11 conservative given its substantial divergence from the midpoint. ll Again, this is likely 

12 due to reduced estimation reliability caused by the continuing uncertain economic 

13 conditions. Moreover, the additional risks arising from the large capital investment 

14 program warrant an upward adjustment. An 11.5 percent ROE is well within the 

IS 

16 

17 

estimated range of reasonableness from the restricted sample and is generally consistent 

with the base level ROE awarded in recent FERC decisions for transmission owning 

utilities that are members of an RTO.12 

18 Q15. How is the rest of your testimony organized? 

19 A IS. Section II formally defines the cost of capital and touches on the principles relating to the 

20 estimation of the cost of capital for a business. It also discusses the impact of the recent 

21 economic turmoil on the cost of equity, making the case for why the estimates obtained 

MW, and they expected to be operational in 2016 and 2019 respectively. They have projected (future value) costs 

of $5.3 billion. The related transmission infrastructure has projected future value costs of $646 million. (Source: 

SCANA 2008 IO-K) 

10 SCANA will recover the carrying costs on its investment in its nuclear generating plant investments based 

upon the Baseload Recovery Act, but the Company's credit metrics will still be weakened by the fact that the 

return of investment, i.e., depreciation, is not included in the current cost recovery for the investment. 

11 The Company has decided to request an allowed ROE of 11.3 percent. 

12 SCE&G is not a member of an RTO, in part because there is currently no RTO to join in the Company's 

area of operation.



Docket ERI 0·_-000 

Page 7 of35 

EXHIBIT 

NO. SCE-13 

2 

3 

4 

5 

6 

using current cost of capital methodologies are likely to be conservative. Section III first 

describes the selection of the Proxy Group. It then describes the Commission's current 

cost of capital estimation methodology based upon the DCF model and provides the 

results of the FERC DCF model for the Full and Restricted Samples. The section 

concludes with the recommended cost of equity for SCE&G's regulated transmission 

assets in the southeastern United States. 

7 II. 

COST OF CAPITAL 

THEORY 

8 

A. THE COST OF CAPITAL AND RISK 

9 Q16. 

10 A16. 

II 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

Please formally define the "Cost of Capital." 

The cost of capital can be defined as the expected rate of return in capital markets on 

alternative investments of equivalent risk. In other words, it is the rate of return investors 

require based on the risk-return alternatives available in competitive capital markets. The 

cost of capital is a type of opportunity cost: it represents the rate of return that investors 

could expect to earn on alternative investments of comparable risk. "Expected" is used in 

the statistical sense: the mean of the distribution of possible outcomes. The terms 

"expect" and "expected" in this testimony, as in the definition of the cost of capital itself, 

refer to the probability-weighted average over all possible outcomes. 

The definition of the cost of capital recognizes a market tradeoff between risk and return 

that is known as the "security market risk-return line," or "security market line" for short. 

This line is depicted in Figure I. The higher the systematic risk, the higher is the cost of 

capital. A version of Figure I applies for all investments. However, for different types 

of securities, the location (i.e., the intercept and the slope) of the line may depend on 

corporate and personal tax rates.




Page 8 of35 


Cost of 

Capital for 

Investment i 

Risk-free 

Interest Rate 

Risk level of 

Investment i 

Risk 

Figure 1: The Security Market Line 

Q17. 

2 A17. 

3 

4 

5 

6 

Why is the cost of capital relevant in rate regulation? 

It has become routine in U.S. rate regulation to accept the "cost of capital" as the right 

expected rate of return on utility investments. 13 That practice is normally viewed as 

consistent with the U.S. Supreme Court's opinions in Bluefield Water Works & 

Improvement Co. v. Public Service Commission of West Virginia, 262 U.S. 679 (1923), 

and Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591 (1944). 

7 

8 

9 

10 

II 

From an economic perspective, rate levels that give investors a fair opportunity to earn 

the cost of capital are the lowest levels that compensate investors for the risks they bear. 

Over the long run, an expected return above the cost of capital makes customers overpay 

for service. Regulatory commissions normally try to prevent such outcomes unless there 

are offsetting benefits (e.g., from incentive regulation that reduces future costs). At the 

13 A formal link between the cost of capital as defined by financial economics and the right expected rate of 

return for utilities is established by Stewart C. Myers, Application of Finance Theory to Public Utility Rate 

Cases, Bell Journal of Economics & Management Science 3:58-97 (1972).




Page 9 of35 


I 

2 

3 

4 

5 

same time, an expected return below the cost of capital does a disservice not just to 

investors but, importantly, to customers as well. In the long run, such a return denies the 

company the ability to attract capital, to maintain its financial integrity, and to expect a 

return commensurate with that of other enterprises attended by corresponding risks and 

uncertainties. 

6 

7 

8 

9 

10 

II 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

More important for customers, however, are the economic issues an inadequate return 

raises for them. In the short run, deviations of the expected rate of return on the rate base 

from the cost of capital may seemingly create a "zero-sum game" -- investors gain if 

customers are overcharged, and customers gain if investors are shortchanged. But in fact, 

in the short run, such actions may adversely affect the utility's ability to provide stable 

and favorable rates because some potential efficiency investments may be delayed or 

because the company is forced to file more frequent rate cases. In the long run, 

inadequate returns are likely to cost customers -- and society generally -- far more than is 

gained in the short run. Inadequate returns lead to inadequate investment, whether for 

maintenance or for new plant and equipment. The costs of an undercapitalized industry 

can be far greater than the short-run gains from shortfalls in the cost of capital. 

Moreover, in capital-intensive industries (such as the electric utility industry), systems 

that take a long time to decay cannot be fixed overnight. Thus, it is in the customers' 

interest not only to make sure the return investors expect does not exceed the cost of 

capital, but also to make sure that the return does not fall short of the cost of capital, 

either. 

22 

23 

24 

25 

26 

27 

Of course, the cost of capital cannot be estimated with perfect certainty, and other aspects 

of the way the revenue requirement is set may mean investors expect to earn more or less 

than the cost of capital, even if the allowed rate of return equals the cost of capital 

exactly. However, a commission that sets rates so investors expect to earn the cost of 

capital on average treats both customers and investors fairly, and acts in the long-run 

interests of both groups.




Page 10 of35 

B. INVESTMENT IN THE TRANSMISSION GRID 

EXHIBIT 

NO. SCE-13 

2 Q18. 

3 A18. 

4 

5 

6 

7 

8 

9 

10 

II 

12 

Has investment in the U.S transmission grid generally been seen as adeqnate? 

No: Although investment in the transmission system has increased substantially over the 

last few years, the need for additional investment in the transmission 

acknowledged. 

Senate that: 

grid is widely 

In July of 2008, Chairman Kelliher testified before the United States 

The United States is just coming out of a long period of sustained 

underinvestment in the power grid. Investment in transmission facilities 

in real terms declined significantly between 1975 and 1998. While 

investment increased somewhat after 1998, expansion of the interstate 

transmi~si~n grid in ~erms of ~ircuit ,?iles i~ 2005 was only 0.5Ifercent. 

Transmission expansIOn was stIlllaggmg behmd demand growth. 

13 Q19. Do you have any other evidence on the need for additional investment in electric 

14 transmission? 

15 A19. Yes. According to the North American Electric Reliability Corporation's ("NERC") 

16 2008 Long-Term Reliability Assessment ("LTRA"), 15 the need for transmission 

17 infrastructure is among the most important issues facing electric reliability in North 

18 

19 

America over the coming ten years. The LTRA acknowledged the longstanding concern 

about lagging transmission investment, and concluded that more transmission is required 

20 to maintain reliability and integrate new generation. 16 Another key finding of the LTRA 

21 is that wind capacity is expected to increase significantly; NERC recommended that 

22 regulators and policy makers support the development of cost effective transmission 

23 

24 

resources for the delivery of remotely located wind resources to demand centers. l7 

NERC also summarized the reliability impacts of inadequate transmission investment: 

14 Testimony of The Honorable Joseph T. Kelliher, Chairman Federal Energy Regulatory Commission, Before 

the Committee on Energy and Natural Resources, United States Senate, July 31. 2008 (available at 

http://www.ferc.gov/eventcalendarlFiles/2008073 II 02 I23-Chairmantestimony .pdf). 

15 Also see, North American Electric Reliability Corporation, 2008 Long-Term Reliability Assessment 2008- 

2017 (October 2008). 

16 LTRA, pp. 15-16. 

l'LTRA,p.14.




Page 11 of35 

EXHIBIT 

NO_ SCE-13 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

As demand grows and generation is built in areas remote from the 

demand, more capacity on the transmission system is needed to meet 

demand. Congestion on transmission lines, as more and more power is 

moved over them, can have a significant impact on reliability. As these 

lines reach their capacity, for example, they are less able to make up the 

difference when neighboring lines are forced out of service due to 

equipment failure, severe weather, or maintenance. Under-investment in 

transmission puts additional strain on existing resources, raising the risk of 

system disturbances, lengthening restoration time when outages do occur, 

and limiting access to remote generation. 18 

II Q20. Why do you raise this issue here? 

12 A20. The continuing concern that investment in the transmission grid has not been adequate 

13 

14 

15 

means that it is in the interest of both customers and shareholders to provide an adequate 

rate of return in order to attract sufficient capital to maintain reliable and efficient electric 

service in the long run. 

16 Q21. Are you saying that the issues with the transmission grid have arisen because the 

17 allowed rate of return was inadequate over a sustained period of time? 

18 A21. The cause of under investment cannot be attributed to any single factor. However, the 

19 

20 

21 

22 

23 

capital requirements needed for environmental upgrades for generation assets, and the 

ongoing uncertainty associated with the restructuring of the industry, may have led 

companies and investors to question whether they had access to the necessary capital. It 

may also have raised questions as to whether the allowed returns were adequate, given 

that uncertainty. 

24 Q22. Will an adequate allowed rate of return solve the problem of iuadequate 

25 transmissiou investment? 

26 A22. No, it is not sufficient, but it is a necessary and critical component. An adequate rate of 

27 

28 

29 

return alone is not enough to guarantee additional investment. Investment in long-lived, 

inflexible assets is extraordinarily risky, and electric transmission assets are very longlived. 

In an environment in which full recovery of an investment in such long-lived 

18 

LTRA, P. 17.



Docket ERI0- -000 

Page 12of35 

EXHIBIT 

NO_ SCE-13 

2 

3 

4 

5 

6 

7 

8 

assets may not be perceived as being assured, investment may lag, particularly 

allowed return does not recognize the risk inherent in such a circumstance. 

if the 

If the 

Commission wants investors to sink capital into transmission assets now, at an 

accelerated rate, it will be necessary to eliminate as many barriers as possible. 

A major 

potential barrier would be a fear on the part of investors that investments will not earn 

returns adequate to justify the long-term risks involved. 

Recent FERC decisions on the 

allowed rate of return on equity for new transmission projects seem to acknowledge this 

• 19 

POInt. 

9 Q23. How does this concern relate to SCE&G at this time? 

10 A23. SCE&G plans a major investment in transmission to connect its new nuclear units. 

1 I Although neither of these projects are the subject of this proceeding, together they 

12 represent a major capital investment program for the Company. My ROE 

13 recommendation does not include any incentive ROE adder for which the Company may 

14 choose to apply in the future. At this time, SCE&G seeks to establish a fair base level 

15 ROE to allow it to access capital markets at a reasonable cost. 

16 Q24. What effect does a large capital investment requirement have on the Company? 

17 A24. Because the Company will not be able to fund the required capital investment strictly 

18 

19 

20 

from internally generated funds, the Company will have to access the capital markets for 

additional debt and equity to finance the required investment in new transmission (and 

generating) assets. Initially, the Company's credit ratios will be adversely affected by the 

21 new capital investments, because debt and interest expense will increase without a 

22 corresponding increase in cost recovery, at least until the transmission assets are included 

23 in rate base. Even without a ratings downgrade, the cost of debt is likely to increase 

24 because investors will be aware of the financial pressure on the Company. 

19 

See, e.g., PATH, 122 FERC ~ 61,188, at P 91.


DirectTestimonyofMichaelJ. Vilbert 

DocketERI0-_-000 

Page13of35 


C. THE IMPACT OF CURRENT MACROECONOMIC CONDITIONS ON THE COST 

OF EQUITY 

Q25. 

What is the likely effect on the cost of capital of the economic conditions 

resulting 

2 

3 A25. 

from the recent financial crisis? 

The current economic situation in the U.S. (as in the rest of the world) is uncertain for 

4 

investors. 

Economic growth has slowed, and although there have been recent signs of 

5 

6 

7 

improvement, economic growth rates are still far from the levels observed in recent years. 

Stock markets worldwide have also lost substantial value, despite recent improvements. 

In the U.S., for example, the S&P 500 is still about 20 percent lower than its value 

8 

immediately prior to the crisis, after having plunged almost 50 percent. 

Moreover, 

9 

volatility continues to be above its historical standards (see Figures 2 and 3 below). 

The 

10 

result of increased uncertainty is that either markets are riskier, or investors' risk aversion 

II 

has increased (or both). 

In either case, this suggests that the cost of capital is higher 

12 

today than in the recent past. 

More importantly, there is still much uncertainty as to 

13 

whether current investor optimism will be vindicated or quashed with the next release of 

14 

15 

economic indicators. 

of unemployment. 

This is especially true for the U.S., given its continuing high level 

16 Q26. What do you mean by the term investor "risk aversion"? 

17 A26. Risk aversion is simply the recognition that investors dislike risk. A fundamental tenet of 

18 

investing is that investors face a risk-return tradeoff in selecting from among the various 

19 

investment options. 

Risk-averse investors can only be induced to accept more risk if the 

20 

21 

22 

23 

expected return is higher. When investors' risk aversion increases, the expected return 

(sometimes called the required return) increases for any level of risk. 2o In other words, 

the market risk premium, the premium required for an average risk stock, is higher when 

investors are more risk averse (all else equal). 

20 The tenn "coefficient of risk aversion" is frequently used in academic articles in conjunction with an 

assumptionregardinginvestors'utility functions. In this testimony,I am usingthe term in a more generic 

sense.



Docket ER 1O-~-OOO 

Page 14 of35 

EXHIBIT 

NO. SCE-13 

Q27. What evidence do you have that market risk and/or investors' risk aversion has 

2 increased? 

3 A27. A number of readily observable factors indicate an increase in either market risk or 

4 

5 

6 

7 

8 

9 

10 

II 

12 

investors' risk aversion (or both). Unprecedented defaults in debt instruments that had 

previously been highly rated (AA or A), such as collateralized debt obligations and 

mortgage-backed securities, and the fall in value of most securities caused investors to 

seek investments that would preserve the value of their investments. As a result, there 

has been a "flight to safety" by investors seeking to maintain the value of their 

investments. In general, investors perceive bonds as less risky (safer) than equity and 

government bonds as safer than corporate bonds. The demand for bonds, particularly 

government debt, increased substantially during the crisis. In fact, at what may have been 

the height of the crisis, the yield on U.S. Treasury bills actually fell below zero!21 

13 

14 

15 

16 

17 

The flight to safety had two other results. First, the yield spread between corporate bonds 

and government bonds increased dramatically during the crisis. Though they are now 

returning to their historical levels, as investors return to the market (see Table 1), the 

losses from the crisis are nevertheless still fresh in people's minds. Investors' confidence 

is likely to stay vulnerable into the foreseeable future. 

21 "Treasury Bills Trade at Negative Rates as Haven Demand Surges", by Daniel Kruger and Cordell Eddings, 

Bloomberg, December 9, 2008.



Docket ER I0-_-000 

Page 15 of35 

EXHIBIT 

NO_ SCE-13 

Table I. Percentage point spreads between U.S. Moody's Utility Bonds and U.S. Treasury Bonds (20 

year maturity) 

Moody's A-Rated Moody's BBB-Rated 

Utility and Utility and 

Periods Government Bonds Government Bonds Notes 

Period I - Average Mar-2002 - Dec-2007 1.30 1.62 [I] 

Period 2 - Average Sep-2008 . Sep-2009 2.37 3.54 [2] 

Period 3 - Average Sep-2009 1.39 1.98 [3] 

Period 4 - Average 15-Day (Sep. 9, 2009 to Sep. 2' 1.38 1.96 [4] 

Spread Increase between Period 2 and Period 1 1.07 1.93 [5] ~ [2]- [I] 



Source: 

Spreads for the periods are calculated from Bloomberg's yield data. 

Average daily yields for the indices were retrieved from Bloomberg as of September 30, 2009. 

2 

3 

4 

5 

6 

7 

Second, as noted earlier, the stock market plummeted in value as investors attempted to 

move out of investments considered risky to those of lower risk. Increased risk aversion 

translates into a requirement for an investment to provide a higher expected return for a 

given level of risk. Under such circumstances, prices of investments fall until investors 

can again expect to earn their (now higher) required rate of return. Of course, part of the 

fall in prices is the result of a fall in expected cash flows, but it is also the result of 

increased market risk and/or risk aversion. 

8 Q28. How different is the overall economic environment now compared to other time 

9 periods in which you have testified? 

10 A28. We now live in a very different economic environment compared to one or two years 

11 ago. The U.S. and world economies are slowly recovering from a state of recession 

12 

13 

14 

triggered by the deep financial crisis that emerged from the U.S. housing bubble, and 

from the use of sophisticated structures that concealed the true risk faced by the investors. 

Stock markets are still down, and markets are only cautiously improving. 

15 

16 

17 

More specifically, as Figure 2 below indicates, the S&P 500 index is now down by 

approximately 20 percent compared to mid-2008, which represents a recovery from a loss 

of about 50 percent earlier in the year.




Page 16 of35 


Daily Prices of the S&P 500 Index 

January 2000 through September 2009 

x 

" 

1,800 

1,600 

1,400 

1,200 

"0 

.5 

1,000 

" u 

." c.. 

800 

600 

400 

200 

0 

- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - --I 

--------1 

------1 

- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - --I 

- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - --I 

I 

Figure 2 

Notes: Prices are pulled from Bloomberg as of September 30, 2009. 

Figure 3 below displays the market volatility, measured by the Chicago Board Options 

2 

3 

Exchange ("CBOE") Volatility Index (also know as VIX), over the period beginning 

January 2000 through the last week of September 2009,22 

22 The VIX is a measure of market expectations of near-term volatility conveyed by S&P 500 stock index 

option prices.


Direct Testimonyof Michael J. Vilbert 


Page 17of35 


CBOE S&P 500 Volatility Index (VIX) 

January 2000 through September 2009 

90,------------------------------------------------------, 

80 --------------------" ------------------------------------- 

70 --------------------------------------------------------- 

60 --------------------------------------------------------- 

50 -------------- - ---------------------------------------- 

40 

30 

20 

10 --------------------- 

O+--r--.-~~--~_,--,__r--._~_,--~_,--,__r--._~_,--~ 

##~~###~##~~##~~#### 

################~#~# 

Source: Data pulled from Bloomberg as of September 30, 2009 

Figure 3 

1 

2 

3 

Prior to the crisis, average volatility was in the 10-20 percent range, but it spiked to 80 

percent in late 2008. Although volatility has decreased substantially over the last couple 

of months, it is still higher than the average value for the first half of 2008. 

4 

5 

6 

The Federal Reserve's efforts to stimulate spending via interest rates cuts have resulted in 

the drop of the federal funds rate as indicated in Figure 4 below. The yield on the 

Treasury bills is also at extraordinarily low levels with yields close to zero.




Page 18 of35 


Federal Funds Effective Rate 

8.0 

7.0 

6.0 

~ 5.0 

~ 

"0 4.0 

0; 

>= 

3.0 

2.0 

1.0 

0.0 

Figure 4 

Source: Federal Reserve Bank 

I 

2 

3 

4 

5 

6 

The lower yields on government debt, however, did not translate into lower yields on 

corporate debt (including the yields on investment grade utility bonds). As Figure 5 

shows, the spreads over Treasury bonds for long-term A and BBB utility debt have fallen 

from their historically high levels but remain higher than the average over the recent past. 

Figure 6 displays the yields on A and BBB-rated utility debt relative to government bond 

yields.




Page 19 of35 

EXHIBIT 

NO. SCE-13 

Spread Between Moody's Utility and 20-yr US Treasury Yields 

6.00 ,---c----c::-----:---~-_:_=-_c_c____::____,_----------_, 

-- Spread Between Moody's A-rated Utility and US 20-yr Bond 

5.00 

4.00 

~ 

'" 

3.00 

'"-0- 

C/O 

2.00 

~~~~-----------~ .1 . " 

- .. Spread Between Moody's BBB-rated Utility and US 20-yr .... _ 

Bond 

I' 

- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - t - -i-:~- - - 

, l 

-- -if"\. - - - -- -- - -. - - -.- - -- - - - - - --- -- - - - - - - -- -- - -- -- - - -. - 

IJ"-' ·,t 'I /' 

,I or.' 

- - - - - - - - - - - - - - - - - - - - - - - -...... - - - - - - - - - - 

1.00 - - - - - - - - - - ., - - - - - - 

0.00 +--__:-~---:-_~-~-_~-_- _ __:-_-__:__:-_,J 

~\:J'\; b ~'\ # r.;:.,r,;:.,% -§>'t! r§>Ot r,;:.,r,;:.,Ot 

",\~" ~\~" ",\~" ~\~" ",\~" ~\~\'V",\~" ~\~" ",\~" ~\~" ",\~" ~\~" ",\~" o,\~" ",\~" ~\~" 

Source: Data pulled from Bloomberg as of September 30, 2009. 

Figure 5 

Moody's Utility and US Treasury Bond Yields 

10.0 

9.0 

I 

A-rated Utility ...... BBB-rated Utility Gov. Bond I 

.....", . " 

8.0 

~~"" ~f\ "". " 

'., 

7.0 

~ 6.0 

~.~,J ..' ,"p' ".A-,' ._ •• -0.~~!ir~ • " ~".. 

" 

ty.."" 

~ 

"" ~ ~;v.... 

5.0 

0; , 

vy V 

.,.~' 

'V 

'" 

;;:; 

4.0 

, 

"'. 

'V 

V'~ 

3.0 1£ 

2.0 

1.0 

0.0 

~~~#~~~#~~~~~~~~~~~#~~ ",,,,~ 

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ G G G G G G 

~~~~~~~~~~~~~~~~~~~~~~~ 

"\ f\,1. ,.;s ,.,,'i.. ,\'i. ,.:s ,,'i.. ,\\ ,v ...,'i. ,\\ ,'$ ...,'\,,'i.. ,..:s ...,'i.. ,\\ ... :,'\ ,,\ ,\\ ,:V ..:j. '\\ 

" 

.AA. 

FIgure 6 

Source: Data pulled from Bloomberg as of September 29, 2009.



Docket ER 10· ·000 

Page 20 of35 


Q29. Is the increase in investors' risk aversion from current economic conditions likely to 

2 be a temporary or permanent change? 

3 A29. It is likely that some of the increase in risk aversion stems from the chaotic market 

4 

5 

6 

7 

conditions and will, I hope, be transitory in nature. But there is a strong possibility that 

there will also be a longer-term and perhaps permanent effect as market participants draw 

conclusions from the crisis on the fundamental risk-return characteristics of investment 

alternatives. 

8 Q30. Why do you believe that some of the increase investors' risk aversion is likely to be 

9 permanent? 

\0 A30. Investors as a group lost substantial wealth as a result of the crisis with the result that 

II 

some investors have been forced to make unpleasant life-style changes. For example, 

12 some have lost their homes or are no longer able to retire as soon as hoped. Life-style 

13 

14 

changes such as these are not likely to be soon forgotten and will affect investors long 

after the turmoil in the markets has receded. 

15 Q31. 

16 

17 A31. 

18 

19 

20 

21 

22 

23 

24 

25 

Aren't the low realized returns on the market index a clear indication that market 

participants are willing to accept a lower expected return on their investments? 

Absolutely not. To the contrary - market values fell in order to allow an increase in the 

expected returns on investment. As risk aversion and/or market risk increases, expected 

returns must increase in order to induce investors to buy, so prices must fall. In other 

words, realized returns over the last few months are not indicative of investors' required 

rate of return. Investors have undoubtedly been disappointed recently. This process is 

well known to bond investors. As the general level of interest rates in the economy 

increases, the market price of a bond will decrease so that the yield-to-maturity increases 

to the level required by the market. The same phenomenon occurs with equities as well. 

When the required return on investment increases, market prices must fall. 

26 Q32. Please summarize this section of your testimony. 

27 A32. The cost of capital increased during the turmoil as investors reacted to the increased




Page 21 of35 


I 

2 

3 

4 

uncertainty, but it also increased because of the effect that the tunnoil had on investors' 

risk aversion. Even though the tunnoil has largely resided, neither investors' confidence 

in the market nor their wealth has returned to pre-crisis levels. As a result, the cost of 

capital is higher today than before the tunnoil in the capital market. 

5 III. THE COMMISSION'S COST OF CAPITAL METHODOLOGY 

6 Q33. How is this section of your testimony organized? 

7 A33. This section first outlines the steps involved in selecting the sample companies used in 

8 the samples. It also describes the discounted cash flow method in general and then 

9 provides the specifics of the implementation of the Commission's preferred DCF 

10 methodology. Finally, the results of my calculations are presented. 

A. THE PROXY GROUP 

1. Selection of the Proxy Group 

II 

12 Q34. Please explain what criteria you applied in selecting a proxy group. 

13 A34. I have reviewed key Commission decisions and selected a sample of electric utilities 

14 based on criteria typically used by the Commission?3 To be included in the sample, a 

15 company (or its holding company) must operate in the southeastern portion of the U.S.;24 

23 My sample selection procedures for the Proxy Group are derived from review of various decisions, including 

Southern California Edison Company, 92 FERC ~ 61,070 (2000) ("Opinion No. 445"); N.Y. State Elec. & 

Gas Corp., 92 FERC ~ 61,169 (2000) ("Opinion No. 447"), order on reh'g, 100 FERC ~ 61,021 (2002) 

("Opinion No. 447-A"), reh 'g denied, 101 FERC ~ 61,037 (2002) ("Opinion No. 447-B"), order on reh 'g, 103 

FERC ~ 61,321 (2003) ("Opinion No. 447-C"); Devon Power LLC, 103 FERC ~ 61,155 (2003); Midwest 

Indep. Transmission Sys. Operator, Inc., 100 FERC ~ 61,292 (2002), reh 'g denied, 102 FERC ~ 61,143 

(2003), aff'd on remand, 106 FERC ~ 61,302 (2004); Bangor Hydro-Elec. Co., 117 FERC ~ 61,129 (2006), 

order on reh'g, 122 FERC ~ 61,265 (2008), order granting clarification, 124 FERC ~ 61,136 (2008) 

("Opinion No. 489"); Trans-Allegheny Interstate Line Co., 119 FERC ~ 61,219 (2007), reh'g denied, 121 

FERC ~ 61,009 (2007); Southern California Edison Company, 122 FERC ~ 61,187 (2008); Golden Spread 

Elec. Coop., Inc., e/ al., v. Southwestern Public Service Co., 123 FERC ~ 61,047 (2008) (Opinion No. 501) 

("Golden Spread'); and PATH, 122 FERC ~ 61,188. 

24 The southeastern U.S. is defined to include Virginia, Tennessee, Kentucky, North Carolina, South Carolina,




Page 22 of35 


2 

3 

4 

5 

6 

be publicly-traded and have available recent price and dividend data; pay dividends; have 

an investment grade credit rating; have available growth rate data from Value Line or 

I/B/E/S (or comparable sources);25 and not be involved in recent. current or forecasted 

merger activity for the six-month period used to calculate the dividend yield. Also, any 

companies whose operations are primarily related to natural gas transmission or 

distribution are excluded from the sample. 

7 Q35. 

8 A35. 

9 

10 

II 

12 

13 

14 

15 

16 

17 

Please describe your selection of the Proxy Group. 

I started with a universe of electric utility companies listed under the Central, East and 

West Electric Utilities industry groups generated by Value Line Investment Survey. I 

eliminated cooperatives, municipality-owned companies and state agencies. Of the 

remaining companies, I then determined each member company's parent holding 

company and eliminated those that were not publicly traded or that had no data available 

from Bloomberg. Additionally, companies with either a dividend cut or substantial M&A 

activity over the most recent six month period were excluded. Application of these 

criteria resulted in a universe of 49 companies. Of these 49 companies, I then restricted 

the sample to include only companies that own transmission assets in the southeastern 

U.S. Table 2 below shows the remaining 14 companies that constitute the Full Sample. 

Georgia, Alabama, Mississippi, Arkansas, Louisiana, Texas and Florida. 

25 I rely upon Bloomberg for analyst forecasts of earnings growth rates instead of I1BIE/S because IIB/E/S 

long-term growth rates are accessible only for subscribers to Thomson Financial. I also use Value Line 

estimates.




Page 23 of35 

EXHIBIT NO_ SCE-13 

Table 2 

No. 

Company 

I American Electric Power Co Inc 

2 Centerpoint Energy Inc 

3 Cleco Corp 

4 Dominion Resources IncN A 

5 Duke Energy Corp 

6 Empire Electric Company 

7 Entergy Corp 

8 FPL Group Inc 

9 OGE Energy Corp 

10 Progress Energy 

II SCANA Corp 

12 Southern Co/The 

13 TECO Energy Inc 

14 Xcel Energy Inc 

Q36. Are there alternative ways to select the proxy group? 

2 A36. Yes. SCANA is not a member of an RTO so one argument for the comparability a 

3 "regionally" based sample group is missing. SCANA is an integrated electric utility in a 

4 state with a traditional regulatory regime. As a result, a nationwide sample of 

5 

6 

traditionally regulated integrated utilities could be an alternative, particularly given the 

fact that SCANA must access capital markets that are nationwide if not worldwide. 

2. Credit Rating Restriction 

7 Q37. Does the FERC sometimes rely on any other restrictions when choosing a sample 

8 group? 

9 A37. Yes. The FERC uses the Company's bond rating as a criterion in selecting companies of 

10 "comparable risk," as outlined in Opinion No. 445. The intent is to avoid including 

II 

12 

13 

companies in the sample that are expected to have substantially different risks and thus 

different costs of capital. Financial theory posits that investors in a company with higher 

risk will expect to earn a higher cost of capital.




Page 24 of35 

EXHIBIT 

NO. SCE-13 

Q38. 

2 

3 A38. 

4 

5 

6 

7 

8 

9 

10 

Is the concept of selecting a sample based upon including companies of "comparable 

risks" theoretically sound? 

Yes. However, I do not believe that a company's specific credit rating is an appropriate 

measurement of risk in this context. 26 Credit ratings measure default risk, rather than 

business risk. The risk of default is not a good measure of the type of risk that affects the 

cost of equity, which is the overall business risk of the company. Bond ratings may be 

related to the debt ratio (i.e., the company's capital structure) but that is only one of 

several ratios and qualitative factors considered by the rating agencies, so the bond rating 

itself is not likely to be a good measure of the financial risk of the sample company's 

equity. 

11 Q39. Do you have any evidence that the estimated return on equity is not related to bond 

12 

rating? 

13 A39. Yes. The rationale for using credit rating to restrict the sample appears to be that the 

14 

15 

16 

17 

18 

19 

companies with the lowest credit rating (BBB-) should have the highest expected return 

on equity, and the companies with the highest credit rating (AA-) should have the lowest 

expected return on equity. However, this view is not well supported by the data. Table 3 

summarizes the cost of equity estimates, applying the FERC DCF method, for the 49 

electric utility companies listed in Value Line, sorted by credit ratings.27 Currently, the 

results do not exhibit a regular relationship between estimated returns and credit ratings. 

Table3 

Credit Rating AA· A+ A A- BBB+ BBB BBB· 

Cost of Equityt 10.15% 10.33% 11.78% 10.48% 11.03% 10.88% 10.53% 

Number of Companies I I 2 4 9 16 7 

Note: 

tMedian cost of equity from the high and low implied cost of equity estimates for the group of 

companies that have the same credit rating. 

26 I agree with the FERC's requirement that companies with non· investment grade bond ratings should be 

omitted from the sample to avoid potential estimation problems associated with fmancial risk. 

27 Of the 46 companies covered in Value Line, only 40 have cost of equity estimates that currently meet the 

requirements for inclusion in the range of reasonableness.



Docket ER IO· ·000 

Page 25 of35 

EXHIBIT 

NO. SCE-13 

1 Q40. 

2 

3 A40. 

4 

5 

6 

7 

8 

9 

10 

I I 

12 

13 

14 

15 

16 

17 

Are there any other reasons why you would recommend not using boud ratings as a 

measurement of risk? 

Yes. Restricting the sample to companies with a credit rating within plus or minus one 

notch of the target company unnecessarily reduces the size of the sample without any 

apparent increase in the comparability of the sample companies. Under the recent FERC 

procedures, the sample is already restricted based on several characteristics, including a 

requirement that sample companies operate in the same region. Further restricting the 

sample by credit rating may result in a very small sample, which, in statistical terms, 

reduces the reliability ofthe estimates. Even ifthe distribution of returns from which the 

sample is drawn is symmetric, a smaller sample increases the possibility that the sample 

returns will be skewed. The possibility of a skewed distribution is one of the reasons 

relied upon in the FERC decision to rely on the median in a previous decision?8 In this 

case, restricting the sample based upon credit ratings reduces the sample size by more 

than 25 percent from 14 to 10 companies. Limiting the sample companies by credit 

rating has the effect of unnecessarily reducing the sample size without a corresponding 

increase in the comparability of the sample companies, and it also potentially increases 

the skewness of the results. 

18 Q41. Do you report results from the sample using the credit rating restriction? 

19 A41. Yes. I report the results with and without the restriction. Although I believe that 

20 

21 

22 

23 

24 

25 

26 

restricting the sample by credit rating does not improve the comparability of the sample, I 

rely on the Restricted Sample, i.e., the sample with the credit rating restriction, in this 

proceeding because the Commission has consistently confirmed its reliance on the credit 

rating restriction. The Restricted Sample includes all companies that pass the initial 

screening process (i.e., operate in a state in the southeastern U.S., publicly traded, pays 

dividends, investment grade bond rating, and no substantial merger and acquisition 

activity) and is further restricted by bond rating. 

28 Skewness is a measure of symmetry of the distribution of sample results. If the sample estimates were not 

skewed, the mean, the median and the midpoint would be identical.




Page 26 of35 

EXHIBIT 

NO. SCE-13 

Q42. 

2 

3 A42. 

4 

5 

6 

7 

8 

9 

10 

II 

12 

Why is it appropriate to include SCANA Corp, the pareut company of SCE&G, in 

the sample? 

SCANA meets all of the conditions necessary for inclusion in the sample. SCANA owns 

transmission assets in the southeastern U.S. and fulfills all other data requirements 

necessary for inclusion in the sample. Including the parent holding company of a 

regulated subsidiary that is the subject of the regulatory proceeding would be of concern 

if there were issues of circularity. Circularity could potentially result if the outcome of 

the regulatory proceeding substantially affects the estimated cost of capital of the holding 

company which is part of the sample being used to estimate the appropriate cost of 

capital. In this case. SCANA's regulated transmission assets make up a relatively small 

percentage of its total assets so any effect is likely to be undetectable by cost of capital 

estimation methods. 

3. Characteristics of the Proxy Group 

13 Q43. Please describe the financial characteristics of the Proxy Group. 

14 A43. Table 4 provides financial information on each of the 14 companies available for 

IS inclusion in either the Full Sample or the Restricted Sample, including each sample 

16 company's S&P Business Profile, 2008 revenue, percentage of regulated assets (as 

17 

18 

characterized by the Edison Electric Institute), market capitalization, S&P credit rating, 

and two estimated growth rates for the DCF model.




Page 27 of35 

Table 4 

EXHIBIT 

NO. SCE-13 

Company 

S&P 

Business 

Profile 

Revenue 

(2008) 

($MM) 

Regulated Market Cap 

Electric (2008) 

Assets ($MM) 

3rd Quarter, Sustainable BEst Long- 

2009Bond Growth Tenn Growth 

Rating Rates Estimate 

Sources and Notes: 

[1]: Issuer Ranking: U.S. Regulated Electric Utilities, Standard & Poor's, RatingsDirect, August 2009. 

When the parent company was not available, its major subsidiary was used instead. 

[2], [4], [5]: Historical Bloomberg data accessed September 11,2009 

[3]: EEl 2008 Financial Review as of December 31, 2008, pp. 25 - 26. 

R = Regulated (greater than 80 percent of total assets are regulated). 

MR = Mostly Regulated (50 to 80 percent of total assets are regulated) 

o = Diversified (less than 50 percent of total assets are regulated). 

[6]: See Workpaper#l to Table No_ MJV·4. 

[7]: See Workpaper #10 to Table No. MJV-4. 

B. THE DISCOUNTEDCASH FLOW APPROACH 

1. The Theoretical DCF Model 

Q44. Please describe the discounted cash flow approach. 

2 A44. The DCF model attempts to estimate the cost of capital in one step. The method assumes 

3 that the market price of a stock is equal to the present value of the dividends that its 

4 owners expect to receive. The method also assumes that this present value can be 

5 calculated by the standard formula for the present value of a cash flow stream: 

D, D2 D3 Dr 

p = -- + + + ...+----'--,,- 

(l+k) (l+k)2 (l+k)3 (l+k), 

(1) 

6 

7 

where "P" is the market price of the stock; "D," is the dividend cash flow expected at the 

end of period t (i.e., subscript period I, 2, 3 or T in the equation); "/r' is the cost of




Page 28 of35 


2 

3 

4 

5 

6 

7 

8 

9 

capital; and "T' is the last period in which a dividend cash flow is to be received. The 

formula just says that the stock price is equal to the sum of the expected future dividends, 

each discounted for the time and risk between now and the time the dividend is expected 

to be received. 

Very often, when the DCF is applied in regulatory proceedings, very strong (i.e., 

unrealistic) assumptions are used that yield a simplification of the standard formula, 

which then can be rearranged to estimate the cost of capital. Specifically, it is assumed 

that investors expect a dividend stream that will grow forever at a steady rate, and if so, 

the market price of the stock will be given by a very simple formula, 

p= D, 

(k- g) 

(2) 

10 

II 

12 

13 

where "D/' is the dividend expected at the end of the first period, "gOO is the perpetual 

growth rate, and "P" and "k" are the market price and the cost of capital, as before. 

Equation (2) is a simplified version of Equation (1) that can be solved to yield the well 

known "DCF formula" for the cost of capital: 

D 

k = -' +g 

P 

Dox(l+g) 

= +g 

P 

(3) 

14 

15 

16 

17 

18 

19 

where "Do" is the current dividend, which investors expect to increase at rate g by the end 

of the next period, and the other symbols are defined as before. Equation (3) says that if 

Equation (2) is satisfied, the cost of equity equals the expected dividend yield plus the 

(perpetual) expected future (forever constant) growth rate of dividends. I refer to this as 

the simple DCF model because this simplification of the model relies on the use of very 

strong assumptions that are unlikely to reflect actual circumstances. 

2. The Commission's Preferred DCF Model 

20 Q45. Please describe the Commission's preferred DCF model.



Docket ER IO· -000 

Page 29 of35 

EXHIBIT 

NO. SCE-13 

2 

3 

4 

5 

6 

7 

8 

9 

10 

II 

12 

13 

14 

A45. 

The Commission's 

uses a constant growth of dividends. 

61,262-63: 

preferred DCF model is a version of the standard DCF model that 

The model is articulated in Opinion No. 445, at 

In the past, we have consistently applied a one-step, constant growth DCF 

model for calculating ROEs for electric utilities. The DCF methodology 

determines the ROE by summing the dividend yield (with an adjustment 

for the quarterly payment of dividends) and expected growth rate. The 

resulting formula is DIP (I +.5g) + g = k, where "DIP" is the dividend 

yield, "g" is the sustainable growth rate of dividends per share, and "k" is 

the resulting ROE. The sustainable growth rate is calculated by the 

following formula: g = br + sv, where "b" is the expected retention ratio, 

"r" is the expected earned rate of return on common equity, "s" is the 

percent of common equity expected to be issued annually as new common 

stock, and "v" is the equity accretion rate. 

15 Q46. Opinion No. 445 references snstainable growth. Please explain how the sustainable 

16 growth rate is determined. 

17 A46. Although companies can experience very high rates of growth from time to time (i.e., 

18 greater than the growth of the economy as a whole), these high rates cannot generally be 

19 expected to last indefinitely. Conversely, very low rates of growth can generally be 

20 expected to improve over time. As implied by the name, the sustainable growth rate of a 

21 company is that which can be expected to be maintained by the company through 

22 

23 

reinvestment of its earnings or additional equity issuances at prices above book value. 

The growth achieved by reinvestment of new earnings depends on both the amount of 

24 earnings retained, b = (I-DividendslNet Income), and on the expected return on equity (r) 

25 those earnings will achieve. On the other hand, growth from new share issues depends 

26 on the percentage of new shares being issued, s, and the equity accretion 

27 

28 

ratIO,v= . [ 1- 1 ] . 

Market - to - Book Ratio 

given as shown in Equation (4): 

Together, the implied sustainable growth rate is 

g = br + sv (4) 

29 Q47. Is the sustainable growtb rate the only growth rate you use in your implementation 

30 

of the Commission's preferred DCF model?




Page 30 of35 

EXHIBIT 

NO. SCE-13 

A47. No. Consistent with the Commission's practice, I also provides estimates based upon a 

2 version of the model where g is set equal to the long-term earnings growth rates from 

3 IIBIE/S provided by security analysts using the same procedure to adjust the dividend 

4 yield. Iuse the BEst earnings growth rate forecasts provided by Bloomberg?9 

5 Q48. How is the dividend yield determined? 

6 A48. The high and low dividend yield is calculated as the 6-month average of the highest 

7 

8 

9 

10 

I I 

monthly closing prices or lowest monthly closing prices divided into the annualized 

current quarterly dividend, i.e., the current dividend times 4. The result of combining the 

high and low dividend yields with the two estimates of the dividend growth rate is four 

estimates of the cost of equity for each sample company. The highest (lowest) of the four 

estimates is reported as the high (low) estimate for the company which in turn are used to 

12 establish the range of reasonableness for the sample. Details on the calculation of each 

13 parameter in Equations (3) and (4) above are provided in Appendix B. 

14 c. PROXY GROUP ESTIMATES AND THE RANGE OF REASONABLENESS 

15 Q49. What are the results of the application of the Commission's DCF methodology to 

16 the sample of transmission-owning companies determined to be comparable to 

17 SCE&G? 

18 A49. Table 5 below summarizes the results of the Commission's DCF methodology using data 

19 

20 

through September 2009. The table presents the high and low estimate for each company 

in the sample as well as summary statistics for both the Full and Restricted Samples. 

21 Q50. What are the results? 

22 A50. For the Full Sample, the estimates range from a low of 7.72 to a high of 16.16; with a 

23 midpoint of 11.94 percent, a median of 11.04 percent, and a mean of 11.28 percent. For 

24 the Restricted Sample (i.e., restricted by bond rating), the range tightens a little with the 

29 BEst is Bloomberg's version of analyst forecasts comparable to I/B/E/S. Neither BEst nor I1BIE/S estimate 

growth rates. Both simply provide a summary offorecasts prepared by security analysts.




Page 31 of35 


bottom estimate rising to 8.76 percent, and the top unchanged at 16.16 percent. 

The 

2 

3 

Restricted Sample has a higher midpoint at 12.46 percent, a median of 11.04 percent 

(unchanged), and a mean of 11.37 percent. 30 

Table 5 

Full Sample Restricted Sample 

Implied Cost of Equity Implied Cost of Equity 

Bond 

Company Rating High Low High Low 

[II [2] [3] [4] [5] 

American Electric Power Co Inc BBB 11.07% 10.49% 11.07% 10.49% 

Cleco Corp BBB 16.16% 8.76% 16.16% 8.76% 

En1ergy Corp BBB 12.59% 10.33% 12.59% 10.33% 

OGE Energy Corp BBB+ 11.71% 10.00"10 11.71% 10.00% 

Centerpoint Energy In:: BBB 14.28% 13.32% 14.28% 13.32% 

Progress Energy Inc BBB+ 12.48% 9.09% 12.48% 9.09% 

DominionResources InC/VA A- 13.75% 10.75% - - 

FPL Group Inc A 12.73% 12.23% - - 

SCANA Corp BBB 11.05% 10.43% 11.05% 10.43% 

SouthemCo A 11.32% 10.00% - - 

TECO Energy Inc BBB 12.55% 10.04% 12.55% 10.04% 

Duke Energy Corp A- 10.20% 7.72% - - 

Xcel Energy Inc BBB+ 11.04% 9.26% 11.04% 9.26% 

Range 16.16% 7.72% 16.16% 8.76% 

Midpoint 11.94% 12.46% 

Median 11.04% 11.04% 

Mean 11.28% 11.37% 

Number of Companies 13 9 


Excluded from tre sample are companies with growth rates greater than 13.3% and cost of equity lower than its 

cost of debt plus 100 bps. 

See Tables and Workpapers accompanying Dr. Vilbert's testimony. 

4 Q51. Has the Commission relied on the midpoint or the median as the appropriate 

5 estimate of the cost of equity for the sample? 

6 A51. In the past, the Commission has consistently relied upon the midpoint of the sample as 

7 the appropriate measure of the cost of equity for the sample. 3 ! In recent decisions, such 

30 Note the range of estimates excludes those from Empire Electric Company since its growth rate exceeds 

13.3 percent. 

31 See Appendix B for a discussion of the decisions utilizing the midpoint in determining the allowed return.




Page 32 of35 

EXHIBIT 

NO. SCE-13 

2 

3 

4 

5 

6 

as "Golden Spread',32 the Commission detennined that the median is the appropriate 

measure for central tendency when setting an ROE for a single utility and when the 

distribution of sample company returns is skewed. 33 The Commission, without 

comment,34 again set the allowed return based upon the midpoint in the PSE&G decision 

issued September 30, 2008, so the Commission's policy on this point does not appear to 

be settled. 

7 Q52. In Table 5 above, the estimated growth rates for the sample companies are 

8 

9 

10 

displayed. Companies with growth rate estimates greater than 13.3 percent have 

been eliminated from the sample, but are all of the remaining growth rate estimates 

sustainable? 

11 A52. The question of sustainability depends critically on the length of time over which the 

12 

13 

14 

IS 

16 

17 

18 

19 

20 

21 

22 

23 

growth rates would apply. Consistent with the Commission's recent "PATH" decision, I 

excluded growth rates that are above the threshold of 13.3 percent as being unsustainable 

as specified in that decision. Security analysts generally limit their earnings growth rate 

forecasts to a five-year period, and clearly they believe that the estimates they provide are 

sustainable over that period. Forecasts made during volatile economic times are going to 

be more uncertain than what is necessary for a completely reliable use of a DCF model, 

which should be kept in mind when evaluating the results. The other set of growth rates 

used in the FERC DCF method are labeled "sustainable" growth rates because they are 

the product of the amount of earnings retained times the average return on equity. 

Growth rates estimated by application of the sustained growth rate methodology can be 

sustained as long as the company continues to retain earnings on which it earns the same 

average return on equity. 

32 123 FERC ~ 61,047. 

33 If the distribution were perfectly symmetric, all three measure of central tendency (the mean, median and 

mid-point) would be identical. 

34 In the PSE&G decision, the Commission accepted my recommend ROE which was based upon the midpoint 

of the sample, but the Commission did not otherwise comment on the relevance of the midpoint or the 

median.




Page 33 of35 

EXHIBIT 

NO_ SCE-13 

I Q53_ Are you saying that higher growth rates could be sustainable forever? 

2 A53. No. Growth rates for all companies vary over time, and no company can maintain a high 

3 growth rate forever. Nor is it likely that some of the very low current estimated growth 

4 rates would stay low forever. For purposes of the DCF analysis, the growth rate 

5 estimates are the best available estimates for the next five years. There is a danger of bias 

6 if some growth rate estimates are arbitrari ly judged not to be sustainable because it 

7 encourages efforts to delete the companies with the highest cost of equity estimates while 

8 leaving the lower estimates in the sample. For a small sample this becomes a serious 

9 problem because the removal of one or two companies has a larger effect. 

10 Q54. What about the growth rates for year six and later? 

II A54. To my knowledge, there is no infonnation available on the likely growth rate of earnings 

12 and dividends available for time periods more than five years in the future. Use of the 

13 DCF model is necessarily subject to this limitation. Analysts sometimes attempt to 

14 

15 

16 

address this problem by making various assumptions about the likely growth path of 

dividends for the period beginning in year six. However, there is no recognized source of 

individual company data upon which to rely in order to make these assumptions. 

17 Q55. What is your conclusion about the growth rates used in your application of the 

18 FERC DCF model? 

19 A55. In my judgment, the question of whether the individual growth rates are sustainable is not 

20 a matter of concern in the current proceeding for two reasons. First, I believe that the 

21 five-year growth rate estimates used in the model come from widely recognized sources 

22 and are the best estimates currently available. Second, the FERC DCF methodology 

23 

24 

25 

attempts to address the lack of data on long-tenn dividend growth rates by estimating the 

five-year growth rate in the two ways discussed above. The method then creates a range 

of reasonableness by looking to the highest and lowest estimates from the two growth 

26 rates and two dividend yield estimates. The likely motivation for this approach is the 

27 belief that the companies with high estimates are balanced by the companies with low 

28 estimates so that the estimation errors cancel out. If the sample is large enough, the




Page 34 of35 

EXHIBIT 

NO. SCE-13 

expectation that the estimation errors for the growth rates are likely to cancel out is 

2 

reasonable. 

This is another reason that a larger sample is preferable. 

3 Q56. 

4 

5 A56. 

6 

7 

8 

9 

10 

II 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

What are your conclusions from the FERC DCF model regarding the cost of equity 

for SCE&G's regulated transmission assets? 

The median for both the Full Sample and the Restricted Sample is 11.04 percent, while 

the midpoints are 11.94 percent and 12.46 percent respectively. As 1noted earlier, in this 

case 1 recommend that the Commission should allow SCE&G an opportunity to earn an 

11.5 percent baseline ROE. This value is indicated for several reasons. First, the cost of 

capital is likely to be higher today than prior to the credit crisis, which suggests that the 

median should be viewed as conservative. Second, the Commission's policy with respect 

to the use of midpoint versus median does not appear to be settled. Most recently the 

Commission adopted the midpoint where the utility was embarking on a major 

transmission expansion, as is the case for SCE&G. 35 According to the Commission, the 

use of the median tends to eliminate outlying extremes in the sample in order to capture 

"central tendencies" of the sample. In this case, the ability of such an effort to capture 

central tendencies is compromised because the sample is so small to begin with, and 

current economic conditions have a greater impact on the reliability of the DCF 

estimation methodology. It is reasonable, therefore, to look at both the midpoints and 

medians of the sample ranges in making a recommendation. In this case, the midpoints 

are 90 to 142 bps higher than the median and suggest that the median is likely a 

conservative estimate of the ROE for the sample. 36 An ROE of 11.5 percent roughly 

splits the difference between the midpoint and the median under the Restricted Sample. 

Third, and most important, SCE&G's circumstances suggest it is of higher relative 

business risk to the sample, which the Commission itself has recognized as requiring 

upward adjustment. As noted in the testimony of Mr. Addison, SCE&G faces relatively 

risky circumstances given the major transmission expansion it is undertaking to 

accommodate new nuclear facilities and given its financial metrics. Although some of 

35 PSE&G, 124FERC, 1161,303. 

36 The sample average is also higher than the median for both the Full and Restricted samples.



Docket ERlO-~-OOO 

Page 35 of35 


the companies in the sample also have major capital investment programs in place. not all 

2 

3 

4 

5 

6 

7 

do. In these circumstances, an upward adjustment is appropriate, and 11.5 percent is well 

within the FERC based range of reasonableness in the Restricted Sample. Moreover, an 

allowed ROE of I 1.5 percent is consistent with the baseline allowed ROE in some recent 

FERC decisions for transmission owning entities that are members of an RTO. Members 

of an RTO have also generally been authorized an additional 50 bps over the median for 

their baseline ROE. As noted earlier, SCE&G is not a member of an RTO, in part, 

8 

because 

there is no RTO in its service area. 

9 Q57. Does this conclude your testimony at this time? 

10 A57. Yes.


VERIFICATION 

Pursuant to 28 U.S.C. § 1746 (2000), I state under penalty of perjury that the foregoing 

testimony is true and correct to the best of my information, knowledge and belief. 

Executed this 23 th day of December 2009. 

~i~viJ·V~t 

Principal 

The Brattle Group





EXPERIENCE OF MICHAEL J. VILBERT



Appendix A 

Docket No. ER10-_-000 


Page A-I 

Appendix A 

Michael Viibert is an expert in cost of capital, financial planning and valuation who has advised 

clients on these matters in the context ofa wide variety of investment and regulatory decisions. He 

has testified or submitted testimony on cost of capital, economic damages, the business purpose and 

economic substance of tax related transactions, valuation of assets in arbitration and the effect of 

regulatory policy changes on the cost of capital. 

He received his Ph.D. in Financial Economics from the Wharton School of the University of 

Pennsylvania, an MBA from the University of Utah, an M.S. from the Fletcher School of Law and 

Diplomacy, Tufts University, and a B.S. degree from the United States Air Force Academy. He 

joined The Brattle Group in 1994 after a career as an Air Force officer, where he served as a fighter 

pilot, intelligence officer, and professor of finance at the Air Force Academy. 

REPRESENTATIVE CONSULTING EXPERIENCE 

• Dr. Vilbert served as the consulting expert in several cases for the U.S. Department 

of Justice and the Internal Revenue Service regarding the business purpose and 

economic substance of a series of tax related transactions. These projects required 

the analysis of a complex series of financial transactions including the review of 

voluminous documentary evidence and required expertise in financial theory, 

financial market as well as accounting and financial statement analysis. 

• In a securities fraud case, Dr. Vilbert designed and created a model to value the 

private placement stock of a drug store chain as if there had been full disclosure of 

the actual financial condition of the firm. He analyzed key financial data and 

security analysts' reports regarding the future of the industry in order to recreate pro 

forma balance sheet and income statements under a variety of scenarios designed to 

establish the value of the firm. 

• For pharmaceutical companies rebutting price-fixing claims in antitrust litigation, Dr. 

Vilbert was a member of a team that prepared a comprehensive analysis of industry 

profitability. The analysis replicated, tested and critiqued the major recent analyses 

of drug costs, risks and returns. The analyses helped develop expert witness 

testimony to rebut allegations of excess profits. 

• For an independent electric power producer, Dr. Vilbert created a model that 

analyzed the reasonableness of rates and costs filed by a natural gas pipeline. The 

model not only duplicated the pipeline's rates, but it also allowed simulation of a 

variety of "what if' scenarios associated with cost recovery under alternative time 

A-I



Appendix A 

Docket No. ERI 0- -000 


Page A-2 

patterns and joint cost allocations. Results of the analysis were adopted by the 

intervenor group for negotiation with the pipeline. 

• For the CFO of an electric utility, Dr. Vilbert developed the valuation model used to 

support a stranded cost estimation filing. The case involved a conflict between two 

utilities over the responsibility for out-of-market costs associated with a power 

purchase contract between them. In addition, he advised and analyzed cost recovery 

mechanisms that would allow full recovery of the stranded costs while providing a 

rate reduction for the company's rate payers. 

• Dr. Vilbert has testified as well as assisted in the preparation of testimony and the 

development of estimation models in numerous cost of capital cases for natural gas 

pipeline, water utility and electric utility clients before the Federal Energy 

Regulatory Commission ("FERC") and state regulatory commissions. These have 

spanned standard estimation techniques (e.g., Discounted Cash Flow and Risk 

Positioning models). He has also developed and applied more advanced models 

specific to the industries or lines of business in question, e.g., based on the structure 

and risk characteristics of cash flows, or based on multi-factor models that better 

characterize regulated industries. 

• Dr. Vilbert has valued several large, residual oil-fired generating stations to evaluate 

the possible conversion to natural gas or other fuels. In these analyses, the expected 

pre- and post-conversion station values were computed using a range of market 

electricity and fuel cost conditions. 

• For a major western electric utility, Dr. Viibert helped prepare testimony that 

analyzed the prudence ofQF contract enforcement. The testimony demonstrated that 

the utility had not been compensated in its allowed cost of capital for major 

disallowances stemming from QF contract management. 

• Dr. Vilbert analyzed the economic need for a major natural gas pipeline expansion to 

the Midwest. This involved evaluating forecasts of natural gas use in various regions 

of the United States and the effect of additional supplies on the pattern of natural gas 

pipeline use. The analysis was used to justify the expansion before the FERC and 

the National Energy Board of Canada. 

• For a Public Utility Commission in the Northeast, Dr. Vilbert analyzed the auction of 

an electric utility'S purchase power agreements to determine whether the outcome of 

the auction was in the ratepayers' interest. The work involved the analysis of the 

auction procedures as well as the benefits to ratepayers of transferring risk of the 

PPA payments to the buyer. 

A-2



Appendix A 

Docket No. ER10-_-OOO 


Page A-3 

• Dr. Vilbert led a team tasked to detennine whether bridge tolls were "just and 

reasonable" for a non-profit port authority. Detennination of the cost of service for 

the authority required estimation of the value of the authority's assets using the 

trended original cost methodology as well as evaluation of the operations and 

maintenance budgets. Investment costs, bridge traffic infonnation and inflation 

indices covering a 75 year period were utilized to estimate the value offour bridges 

and a passenger transit line valued in excess of $1 billion. 

• Dr. Vilbert helped a recently privatized railroad in Brazil develop an estimate of its 

revenue requirements, including a detennination ofthe railroad's cost of capital. He 

also helped evaluate alternative rate structures designed to provide economic 

incentives to shippers as well as to the railroad for improved service. This involved 

the explanation and analysis of the contribution margin of numerous shipper 

products, improved cost analysis and evaluation of bottlenecks in the system. 

• For a utility in the Southeast, Dr. Vilbert quantified the company's stranded costs 

under several legislative electric restructuring scenarios. This involved the 

evaluation of all of the company's fossil and nuclear generating units, its contracts 

with Qualifying Facilities and the prudence of those QF contracts. He provided 

analysis concerning the impact of securitizing the company's stranded costs as a 

means of reducing the cost to the ratepayers and several alternative designs for 

recovering stranded costs. 

• For a recently privatized electric utility in Australia, Dr. Vilbert evaluated the 

proposed regulatory scheme of the Australian Competition and Consumer 

Commission for the company's electric transmission system. The evaluation 

highlighted the elements of the proposed regulation which would impose 

uncompensated asymmetric risks on the company and the need to either eliminate the 

asymmetry in risk or provide additional compensation so that the company could 

expect to earn its cost of capital. 

• For an electric utility in the Southwest, Dr. Vilbert helped design and create a model 

to estimate the stranded costs of the company's portfolio of Qualifying Facilities and 

Power Purchase contracts. This exercise was complicated by the many variations in 

the provisions of the contracts that required modeling in order to capture the effect of 

changes in either the perfonnance of the plants or in the estimated market price of 

electricity. 

• Dr. Vilbert helped prepare the testimony responding to a FERC request for further 

comments on the appropriate return on equity for electric transmission facilities. In 

addition, Dr. Vilbert was a member of the team that made a presentation to the FERC 

staff on the expected risks of the unbundled electric transmission line of business. 

A-3



Appendix A 

Docket No. ERIO- -000 


Page A-4 

• Dr. Vilbert and Mr. Frank C. Graves, also of The Brattle Group, prepared testimony 

evaluating an innovative Canadian stranded cost recovery procedure involving the 

auctioning of the output of the province's electric generation plants instead of the 

plants themselves. The evaluation required the analysis of the terms and conditions 

of the long-term contracts specifying the revenue requirements of the plants for their 

entire forecasted remaining economic life and required an estimate of the cost of 

capital for the plant owners under this new stranded cost recovery concept. 

• Dr. Vilbert served as the neutral arbitrator for the valuation of a petroleum products 

tanker. The valuation required analysis of the Jones Act tanker market and the 

supply and demand balance of the available U.S. constructed tanker fleet. 

• Dr. Vilbert evaluated the appropriate "bareboat" charter rate for an oil drilling 

platform for the renewal period following the end of a long-term lease. The 

evaluation required analysis of the market for oil drilling platforms around the world 

including trends in construction and labor costs and the demand for platforms in 

varying geographical environments. 

PRESENTATIONS 

"Utility Distribution Cost of Capital," EEl Electric Rates Advanced Course, Bloomington, IN, 2002, 

2003. 

"Issues for Cost of Capital Estimation," with Bente Villadsen, Edison Electric Institute Cost of 

Capital Conference, Chicago, IL, February 2004. 

"Not Your Father's Rate of Retum Methodology," Utility CommissionerslWall Street Dialogue, NY, 

May 2004. 

"Utility Distribution Cost of Capital, "EEl Electric Rates Advanced Course, Madison, WI, July 2004. 

"Cost of Capital Estimation: Issues and Answers," MidAmerican Regulatory Finance Conference, 

Des Moines, lA, April 7, 2005. 

"Cost of Capital - Explaining to the Commission - Different ROEs for Different Parts of the 

Business," EEl Economic Regulation & Competition Analysts Meeting, May 2, 2005. 

"Current Issues in Cost of Capital," with Bente Villadsen, EEl Electric Rates Advanced Course, 

Madison, WI, 2005. 

A-4



Appendix A 

Docket No. ERlO-_-OOO 


Page A-5 

"Current Issues in Estimating the Cost of Capital," EEl Electric Rates Advanced Course, Madison, 

WI, 2006, 2007, 2008, and 2009. 

"Revisiting the Development of Proxy Groups and Relative Risk Analysis," Society of Utility and 

Regulatory Financial Analysts: 39 th Financial Forum, April 2007. 

"Current Issues in Explaining the Cost of Capital to Utility Commissions" Cost of Capital Seminar, 

Philadelphia, PA, 2008. 

"Impact ofthe Ongoing Economic Crisis on the Cost of Capital ofthe U.S. Utility Sector", New 

York Public Service Commission, Albany, NY, April 20, 2009. 

"Impact ofthe Ongoing Economic Crisis on the Cost of Capital of the U.S. Utility Sector", National 

Association of Water Companies: New York Chapter, Albany, NY, May 21, 2009 

ARTICLES 

"Flaws in the Proposed IRS Rule to Reinstate Amortization of Deferred Tax Balances Associated 

with Generation Assets Reorganized in Industry Restructuring," by Frank C. Graves and Michael J. 

Vilbert, white paper for Edison Electric Institute (EEl) to the IRS, July 25, 2003. 

"The Effect of Debt on the Cost of Equity in a Regulatory Setting," by A. Lawrence Kolbe, Michael 

1. Vilbert, Bente Villadsen and The Brattle Group, Edison Electric Institute, April 2005. 

"Measuring Return on Equity Correctly: Why current estimation models set allowed ROE too low," 

by A. Lawrence Kolbe, Michael J. Vilbert and Bente Villadsen, Public Utilities Fortnightly, August 

2005. 

"Understanding Debt Imputation Issues," by Michael 1. Vilbert, Bente Villadsen and Joseph B. 

Wharton, Edison Electric Institute, August 2008. 

TESTIMONY 

Direct and rebuttal testimony before the Alberta Energy and Utilities Board on behalf ofTransAlta 

Utilities Corporation in the matter of an application for approval of its 1999 and 2000 generation 

tariff, transmission tariff, and distribution revenue requirement, Docket U99099, October 1998. 

A-5



Appendix A 

Docket No. ERIO-_-OOO 


Page A-6 

Direct testimony before the Federal Energy Regulatory Commission on behalf of Central Maine 

Power in Docket No. EROO-982-000, December 1999. 

Direct testimony before the Alberta Energy and Utilities Board on behalf of TransAlta Utilities 

Corporation for approval of its 2001 transmission tariff, May 2000. 

Direct testimony before the Federal Energy Regulatory Commission on behalf of Mississippi River 

Transmission Corporation in Docket No. RPO1-292-000, March 200 I. 

Written evidence, rebuttal, reply and further reply before the National Energy Board in the matter of 

an application by TransCanada PipeLines Limited for orders pursuant to Part I and Part IV of the 

National Energy Board Act, Order AO-I-RH-4-2001, May 2001, Nov. 2001, Feb. 2002. 

Written evidence before the Public Utility Board on behalf of Newfoundland & Labrador Hydro - 

Rate Hearings, October 2001, Order No. P.U.7 (2002-2003), dated June 2002. 

Direct testimony (with William Lindsay) before the Federal Energy Regulatory Commission on 

behalf of DTE East China, LLC in Docket No. ER02-1599-000, April 2002. 

Direct and rebuttal reports before the Arbitration Panel in the arbitration of stranded costs for the 

City of Casselberry, FL, Case No. 00-CA-II07-16-L, July 2002. 

Direct reports before the Arbitration Board for Petroleum products trade in the Arbitration of the 

Military Sealift Command vs. Household Commercial Financial Services, fair value of sale of the 

Darnell, October 2002. 

Direct testimony and hearing before the Arbitration Panel in the arbitration of stranded costs for the 

City of Winter Park, FL, In the Circuit Court of the Ninth Judicial Circuit in and for Orange County, 

FL, Case No. CI-01-4558-39, December 2002. 

Direct testimony before the Federal Energy Regulatory Commission on behalf of Florida Power 

Corporation, dba Progress Energy Florida, Inc. in Docket No. SC03-1-000, March 2003. 

Direct report before the Arbitration Panel in the arbitration of stranded costs for the Town of 

Belleair, FL, Case No. 000-6487-CI-007, April 2003. 

Direct and rebuttal reports before the Alberta Energy and Utilities Board in the matter of the Alberta 

Energy and Utilities Board Act, R.S.A. 2000, c. A-17, and the Regulations under it; in the matter of 

the Gas Utilities Act, R.S.A. 2000, c. G-5, and the Regulations under it; in the matter ofthe Public 

Utilities Board Act, R.S.A. 2000, c. P-45, as amended, and the Regulations under it; and in the 

matter of Alberta Energy and Utilities Generic Cost of Capital Hearing, Application No. 1271597, 

July 2003, November 2003, Decision 2004-052, dated July 2004. 

A-6



Appendix A 



Page A-7 

Written evidence before the National Energy Board in the matter of the National Energy Board Act, 

R.S.C. 1985, c. N-7, as amended, (Act) and the Regulations made under it; and in the matter of an 

application by TransCanada PipeLines Limited for orders pursuant to Part IV of the National Energy 

Board Act, for approval of Mainline Tolls for 2004, RH-2-2004, January 2004. 

Direct and rebuttal testimony before the Public Service Commission of West Virginia, on Cost of 

Capital for West Virginia-American Water Company, Case No 04-0373-W-42T, May 2004. 

Direct and rebuttal testimony before the Federal Energy Regulatory Commission on Energy 

Allocation of Debt Cost for Incremental Shipping Rates for Edison Mission Energy, Docket No. 

RP04-274-000, December 2004 and March 2005. 

Direct testimony before the Arizona Corporation Commission, Cost of Capital for Paradise Valley 

Water Company, a subsidiary of Arizona-American Water Company, Docket No. WS-01303A-05, 

May 2005. 

Written evidence before the Ontario Energy Board, Cost of Capital for Union Gas Limited, Inc., 

Docket No. EB-2005-0520, January 2006. 

Direct and rebuttal testimony before the Pennsylvania Public Utility Commission, Return on Equity 

for Metropolitan Edison Company, Docket No. R-00061366 and Pennsylvania Electric Company, 

Docket No. R-00061367, April 2006 and August 2006. 

Expert report in the United States Tax Court, Docket No. 21309-05, 34th Street Partners, DH 

Petersburg Investment, LLC and Mid-Atlantic Finance, Partners Other than the Tax Matters Partner, 

Petitioner, v. Commissioner oflnternal Revenue, Respondent, July 28, 2006. 

Direct and supplemental testimony before the Federal Energy Regulatory Commission, Docket No. 

ER06-427-003, on behalf of Mystic Development, LLC on the Cost of Capital for Mystic 8 and 9 

Generating Plants Operating Under Reliability Must Run Contract, August 2006 and September 

2006. 

Direct testimony before the Federal Energy Regulatory Commission, Docket No. ER07-46-000, on 

behalf of Northwestern Corporation on the Cost of Capital for Transmission Assets, October 2006. 

Direct and rebuttal testimony before the Tennessee Regulatory Authority, Case No. 06-00290, on 

behalf of Tennessee American Water Company, on the Cost of Capital, November, 2006 and April 

2007. 

Direct and rebuttal testimony before the Public Service Commission of Wisconsin, Docket No. 5- 

UR-103, on behalf of Wisconsin Energy Corporation, on the Cost of Capital for Wisconsin Electric 

A-7



Appendix A 

Docket No. ER10- -000 


Page A-8 

Power Company and Wisconsin Gas LLC, May 2007 and October 2007. 

Rebuttal testimony before the Califomia Public Utilities Commission, Docket No. A. 07-01-036-39, 

on behalf of California-American Water Company, on the Cost of Capital, May 2007. 

Direct testimony before the Public Utilities Commission of the State of South Dakota, Docket No. 

NG-07-013, on behalf of NorthWestern Corporation, on the Cost of Capital for NorthWestern 

Energy Company's natural gas operations in South Dakota, June 2007. 

Direct, supplemental and rebuttal testimony before the Public Utilities Commission of Ohio, Case 

No. 07-551-EL-AIR, Case No. 07-552-EL-ATA, Case No. 07-553-EL-AAM, and Case No. 07-554- 

EL-UNC, on behalf of Ohio Edison Company, The Toledo Edison Company, and The Cleveland 

Electric Illuminating Company, on the cost of capital for the FirstEnergy Company's Ohio electric 

distribution utilities, June 2007, January 2008 and February 2008. 

Direct testimony before the Public Service Commission of West Virginia, Case No. 07-0998- W- 

42T, on behalf of West Virginia American Water Company on cost of capital, July 2007. 

Direct and rebuttal testimony before the State Corporation Commission of Virginia, Case No. PUE- 

2007-00066, on behalf of Virginia Electric and Power Company on the cost of capital for its 

southwest Virginia coal plant, July 2007 and December 2007. 

Direct and Supplemental testimony before the Public Utilities Commission of Ohio, Case No. 07- 

829-GA-AIR, Case No. 07-830-GA-ALT, and Case No. 07-831-GA-AAM, on behalf of Dominion 

East Ohio Company, on the rate of return for Dominion East Ohio's natural gas distribution 

operations, September 2007 and June 2008. 

Direct testimony before the Federal Energy Regulatory Commission, Docket No. ER08-92-000 to 

Docket No. ER08-92-003, on behalf of Virginia Electric and Power Company, on the Cost of Capital 

for Transmission Assets, October 2007. 

Direct and rebuttal testimony before the California Public Utilities Commission, Docket No. A. 07- 

01-022, on behalf of California-American Water Company, on the Effect of a Water Revenue 

Adjustment Mechanism on the Cost of Capital, October 2007 and November 2007. 

Written direct and reply evidence before the National Energy Board in the matter of the National 

Energy Board Act, R.S.C. 1985, c. N-7, as amended, and the Regulations made thereunder; and in 

the matter of an application by Trans Quebec & Maritimes PipeLines Inc. ("TQM") for orders 

pursuant to Part I and Part IV of the National Energy Board Act, for determining the overall fair 

return on capital for tolls charged by TQM, December 2007 and September 2008, Decision RH-I- 

2008, dated March 2009. 

A-8



Appendix A 


EXHIBIT 

NO_ SCE-14 

Page A-9 

Comments in support of The Interstate Natural Gas Association of America's Additional Initial 

Comments on the FERC's Proposed Policy Statement with regard to the Composition of Proxy 

Companies for Detennining Gas and Oil Pipeline Return on Equity, Docket No. PL07-2-000, 

December, 2007. 

Direct and rebuttal testimony on the Cost of Capital before the Tennessee Regulatory Authority, 

Case No. 08-00039, on behalf of Tennessee American Water Company, March and August 2008. 

Post-Technical Conference Affidavit on behalf of The Interstate Natural Gas Association of America 

in response to the Reply Comments of the State of Alaska with regard the FERC's Proposed Policy 

Statement on to the Composition of Proxy Companies for Detennining Gas and Oil Pipeline Return 

on Equity, Docket No. PL07-2-000, March, 2008 

Direct and rebuttal testimony before the California Public Utilities Commission, Docket No. A.08- 

05-003, on behalf of California-American Water Company, concerning Cost of Capital, May 2008 

and August 2008. 

Rebuttal testimony on the financial risk of Purchased Power Agreements, before the Public 

Utilities Commission of the State of Colorado, Docket No. 07A-447E, in the matter of the 

application of Public Service Company of Colorado for approval of its 2007 Colorado Resource 

Plan, June 2008. 

Direct testimony before the Federal Energy Regulatory Commission, Docket No. RP08-426-000, 

on behalf of El Paso Natural Gas Company, on the Cost of Capital for Natural Gas Transmission 

Assets, June 2008 and August 2009. 

Direct testimony before the Federal Energy Regulatory Commission, Docket No. ER08-l207-000, 

on behalf of Virginia Electric and Power Company, on the incentive Cost of Capital for investment 

in New Electric Transmission Assets, June 2008 

Direct testimony before the Federal Energy Regulatory Commission, Docket No. ER08-l233-000, 

on behalf of Public Service Electric and Gas Company, on the Cost of Capital for Electric 

Transmission Assets, July 2008. 

Direct and rebuttal testimony before the Public Service Commission of West Virginia, Case No. 08- 

0900-W-42t, on behalf of West Virginia-American Water Company concerning the Cost of Capital 

for Water Utility assets, July 2008 and November 2008. 

Direct and rebuttal testimony before the Public Utilities Commission of Ohio, Case No. 08-935-EL- 

SSO, on behalf of Ohio Edison Company, The Toledo Edison Company, and The Cleveland Electric 

Illuminating Company, with regard to the test to detennine Significantly Excessive Earnings within 

the context of Senate Bill No. 221, September 2008 and October 2008. 

A-9



Appendix A 

Docket No. ER 10- -000 


Page A-1O 


behalf of Public Service Electric and Gas Company, on the incentive Cost of Capital for Mid- 

Atlantic Power Pathway Electric Transmission Assets, November 2008. 

Direct and rebuttal testimony before the Public Service Commission of West Virginia, Case No. 08- 

1783-G-PC, on behalf of Dominion Hope Gas Company concerning the Cost of Capital for Gas 

Local Distribution Company assets, November 2008 and May 2009. 

Written Evidence before the Alberta Utilities Commission in the matter of the Alberta Utilities 

Commission Act, S.A. 2007, c. A-37.2, as amended, and the regulations made thereunder; and IN 

THE MATTER OF the Gas Utilities Act, R.S.A. 2000, c. G-5, as amended, and the regulations made 

thereunder; and IN THE MATTER OF the Public Utilities Act, R.S.A. 2000, c. P-45, as amended, 

and the regulations made thereunder; and IN THE MATTER OF Alberta Utilities Commission 2009 

Generic Cost of Capital Hearing, Application No. I5785711Proceeding No. 85. 2009 Generic Cost of 

Capital Proceeding on behalf ofNGTL, November 2008. 

Written and Reply Evidence before the Alberta Utilities Commission in the matter of the Alberta 

Utilities Commission Act, S.A. 2007, c. A-37.2, as amended, and the regulations made thereunder; 

and IN THE MATTER OF the Gas Utilities Act, R.S.A. 2000, c. G-5, as amended, and the 

regulations made thereunder; and IN THE MATTER OF the Public Utilities Act, R.S.A. 2000, c. P- 

45, as amended, and the regulations made thereunder; and IN THE MATTER OF Alberta Utilities 

Commission 2009 Generic Cost of Capital Hearing, Application No. 157857l1Proceeding No. 85. 

2009 Generic Cost of Capital Proceeding on behalf of AltaGas Utilities Inc., November 2008 and 

May 2009. 


behalf ofITC Great Plains, LLC, on the Cost of Capital for Electric Transmission Assets, January 

2009. 

Direct testimony before the Federal Energy Regulatory Commission, Docket No. ER09-68 1-000, on 

behalf of Green Power Express, LLP, on the Cost of Capital for Electric Transmission Assets, 

February 2009. 

Written evidence before the Regie de I'Energie on behalf ofGaz Metro Limited Partnership, Cause 

Tarifaire 2010, R-3690-2009, on the Cost of Capital for natural gas transmission assets, May 2009. 

Direct and rebuttal testimony before the Public Service Commission of Wisconsin, Docket No. 

6680-UR-117, on behalf of Wisconsin Power and Light Company, on the cost of capital for electric 

and natural gas distribution assets, May 2009 and September 2009. 

Direct testimony before the State of New Jersey Board of Public Utilities in the Matter of the 

A-IO



Appendix A 



Page A-ll 

Petition of Public Service Electric and Gas Company for Approval of an Increase in Electric and Gas 

Rates and for Changes in the Tariffs for Electric and Gas Service, B.P.U.NJ. No. 14 Electric and 

B.P.U.NJ No. 14 Gas Pursuant to NJ.S.A. 48:2-21 and NJ.S.A. 48:2-21.1 and for Approval ofa 

Gas Weather Normalization Clause; a Pension Expense Tracker and for other Appropriate Relief 

BPU Docket No. GR09050422, June 2009. 

Rebuttal testimony before the Florida Public Service Commission in re: Petition for Increase in 

Rates by Progress Energy Florida, Inc., Docket No. 090079-EI, August 2009. 

Direct Testimony before the California Public Utilities Commission regarding cost of service for 

San Joaquin Valley crude oil pipeline on behalf of Chevron Products Company, Docket Nos. 

A.08-09-024, C.08-03-021, C.09-02-007 and C.09-03-027, December 2009. 

A-II




EXHIBIT 

NO. SCE-IS 

APPENDIXB 

THE FERC METHODOLOGY: SAMPLE SELECTION AND THE DCF METHOD



Appendix B 

Docket No. ERI0- -000 

EXHIBIT NO. SCE-IS 

Page B-i 

APPENDIXB 

THE FERC METHODOLOGY: 

SAMPLE SELECTION AND THE DCF METHOD 

I. SAMPLE SELECTION 1 

II. THE DISCOUNTED CASH FLOW APPROACH 3 

A. STRENGTHSANDWEAKNESSESOFTHEDCF ApPROACH 5 

B. THE COMMISSION'SPREFERREDDCF METHOD 6



AppendixB 


Docket No. ERIO- -000 Page B-1 

I. SAMPLE SELECTION 

2 Q1. 

3 AI. 

4 

5 

6 

7 

8 

9 

10 

I I 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

How did you select your two samples of transmission utilities? 

I rely on the precedents set by the Commission in choosing proxy groups lD past 

transmission rate cases. In its recent decisions, the Commission has approved proxy 

groups composed of either (I) transmission-owning companies that operate in interrelated 

ISOs or RTOs or (2) transmission-owning companies that operate in the "broader, but 

inter-related RTO markets" in which the applicant operates and which have a "direct 

link" or "direct correlation" with the applicant's RTO/ISO. For example, in Midwest 

Independent Transmission System Operator, Inc., the Commission affirmed the presiding 

judge's ruling that the group of nine Midwest ISO transmission owners or parent 

corporations of the Midwest ISO transmission owners ("TO") with publicly-traded 

common stock was the appropriate proxy group in determining the return on equity 

("ROE") for the Midwest ISO transmission owners. I 

In Bangor Hydro-Electric Co., Opinion No. 489,2 the Commission agreed with the ALJ's 

initial decision to reject the argument that ISO New England's ROE should be set at a 

level comparable to that established by the Commission for the Midwest ISO. The 

Commission affirmed the judge's ruling, stating "[u]sing the Midwest ISO as the sole 

proxy would, in this instance, be inappropriate and must be rejected.") In an earlier case 

regarding the establishment of ISO-New England as an RTO, the Commission accepted 

the filing parties' proposed proxy group consisting of transmission-owning members 

located in ISO New England ("ISO-NE"), the New York ISO ("NYISO"), and PJM. 4 

The Commission accepted the proxy group on the grounds that a sample of northeast 

I Midwest Indep. Transmission Sys. Operator, Inc., 100 FERC 11 61, 292, at P 12 (2002) ("Midwest ISO"). 

2 Bangor Hydro-Electric Co., 117 FERC 11 61, 129 (2006) ("Bangor Hydro"). 

3 !d., P 74. 

4 ISO New England, Inc., 109 FERC 11 61,147, at P 204 (2004) ("New England RTO Rehearing Order").



Appendix B 

Docket No. ER10-_-000 

EXHIBIT NO. seE-IS 

Page B-2 

2 

3 

4 

5 

6 

7 

8 

9 

10 

II 

12 Q2. 

13 A2. 

14 

15 

16 

17 

18 

19 

20 

21 

utility companies was "a sufficiently representative universe of companies for calculating 

an ROE applicable to the New England Transmission Owners."s 

The most recent Commission precedent seems to be to select a sample from RTOs 

interconnected to the RTO in which the applicant is located. For example, in the case of 

Virginia Electric and Power Company, an entity integrated into P1M, the Commission 

accepted firms located in P1M, NYISO, and ISO-NE as appropriate for inclusion in the 

proxy group.6 

However, when a company is not a member of an RTO, as is the case with SCE&G, the 

sample is determined by taking companies that own transmission assets in the same 

geographical region as the company in question. Since SCE&G operates in South 

Carolina, I consider companies that are located in the southeastern U.S. 7 

Please elaborate on how companies in the sample were selected. 

I started with a universe of electric utility companies listed under the Central, East and 

West Electric Utilities industry groups generated by Value Line Investment Survey. All 

cooperatives, municipality-owned companies and state agencies were removed from the 

universe. I then determined each remaining company's parent holding company and 

eliminated those member companies that were not publicly traded, did not have an 

investment grade bond rating, had a dividend cut in the last six months, had announced a 

significant merger or acquisition in the last six months, or had no data available from 

Bloomberg. Table 1 below is a list of the fourteen remaining companies, including some 

relevant characteristics. 

5 Ibid. 

, Virginia Electric and Power Company, 124 FERC 1161,207 (2008) at P 114, n. 62. 

7 The southeastern U.S. is defined to include Virginia, Tennessee, Kentucky, North Carolina, South Carolina, 

Georgia, Alabama, Mississippi, Arkansas, Louisiana, Texas and Florida.



Appendix B 

Docket No. ERI O· -000 

Table 1 

EXHIBIT 

NO. SCE-IS 

Page B-3 

Company 

S&P 

Business 

Profile 

[1] 

Revenue Regulated 

(2008) Electric 

($MM) Assets 

[2] [3] 

Market Cap 

(2008) 

($MM) 

[4] 

3rd Quarter, Sustainable BEst Long- 

2009 Bond Growth Term Growth 

Rating Rates Estimate 

[5] [6] [7] 


[1]: Issuer Ranking: U.S. Regulated Electric Utilities, Standard & Poor's, RatingsDirect, August 2009. 

When the parent company was not available, its major subsidiary was used instead. 

[2], [4], [5]: Historical Bloomberg data accessed September 11,2009. 

[3]: EEl 2008 Financial Review as of December 31,2008, pp. 25 - 26. 

R =- Regulated (greater than 80 percent of total assets are regulated). 

MR = Mostly Regulated (50 to 80 percent of total assets are regulated). 

D '" Diversified (less than 50 percent of total assets are regulated). 

[6]: See Workpaper #1 to Table No. MJV-4. 

[7]: See Workpaper #10 to Table No. MJV-4 

I 

2 

3 

4 

From these fourteen companies, I provide the results from two samples: I) the Full 

Sample, unrestricted by bond rating, and 2) the Restricted Sample, which limits the 

sample to companies with bond ratings plus or minus one notch of SCE&G's long-term 

issuer credit rating ofBBB (i.e., with the ratings ofBBB- to BBB+). 

5 II. 

THE DISCOUNTED 

CASH FLOW APPROACH 

6 

7 

8 

9 

10 

Q3. 

A3. 

Please describe the discounted cash flow approach. 

The DCF model attempts to estimate the cost of capital in one step. The method assumes 

that the market price of a stock is equal to the present value of the dividends that its 

owners expect to receive. The method also assumes that this present value can be 

calculated by the standard formula for the present value of a cash flow stream:


Direct Testimony of Michael J. Viibert EXHIBIT NO. SeE-IS 

AppendixB 

Docket No. ERIO- -000 Page B-4 

D D D D 

p; __ I_+ 2 + 3 + ... + T 

(l+k) (l+k)' (l+k)3 (l+k)' (B-1) 

where "P" is the market price of the stock; "D/" is the dividend cash flow expected at the 

2 

3 

4 

5 

6 

end of period t (i.e., subscript period 1, 2, 3 or T in the equation); "k" is the cost of 

capital; and "T' is the last period in which a dividend cash flow is to be received. The 

formula just says that the stock price is equal to the sum of the expected future dividends, 

each discounted for the time and risk between now and the time the dividend is expected 

to be received. 

7 

8 

Very often, when the DCF is applied in regulatory proceedings, very strong (i.e., 

unrealistic) assumptions are used that yield a simplification of the standard formula, 

9 

10 

which then can be rearranged to estimate the cost of capital. 

that investors expect a dividend stream that will grow forever 

Specifically, it is assumed 

at a steady rate, and if so, 

11 

the market price of the stock will be given by a very simple formula, 

12 

P= DI 

(k- g) 

where "D/' is the dividend expected at the end of the first period, "gOO 

(B-2) 

is the perpetual 

13 

14 

15 

growth rate, and "P" and "k" are the market price and the cost of capital, as before. 

Equation (B-2) is a simplified version of Equation (B-1) that can be solved to yield the 

well known "DCF formula" for the cost of capital: 

D 

k; _I +g 

P 

Dox(l+g) 

; +g 

P 

(B-3) 

16 

where" Do" is the current dividend, which investors expect to increase at rate g by the end 

17 

ofthe next period, and the other symbols are defined as before. 

Equation (B-3) says that 

18 

if Equation (B-2) is satisfied, the cost of equity equals the expected dividend yield plus 

19 

the (perpetual) expected future (forever constant) growth rate of dividends. 

I refer to this 

20 

21 

as the simple DCF model because this simplification of the model relies on the use of 

very strong assumptions that are unlikely to reflect actual circumstances.



AppendixB 

DocketNo. ERI0- -000 

EXHIBIT 

NO. SCE-15 

Page B-5 

Q4. Are there other versions of the DCF models besides the "simple" one? 

2 A4. Yes. The constant growth rate DCF model requires that dividends and earnings grow at 

3 the same rate for companies that earn their cost of capital on average. s It is inconsistent 

4 with the theory on which the model is based to have different growth rates in earnings 

5 and dividends over the period when growth is assumed to be constant. If the growth in 

6 dividends and earnings were expected to vary over some number of years before settling 

7 down into a constant growth period, then it would be appropriate to estimate a multistage 

8 DCF model. In the multistage model, earnings and dividends can grow at different rates, 

9 but must grow at the same rate in the final, constant growth rate period. A difference 

10 between forecasted dividend and earnings rates therefore is a signal that the facts do not 

II fit the assumptions of the simple DCF model. 

12 A. STRENGTHS ANDWEAKNESSES OF THE DCF APPROACH 

13 Q5. What are the merits of the DCF approach? 

14 AS. The DCF approach is conceptually sound if its assumptions are met, but can run into 

IS 

16 

17 

18 

19 

20 

21 

difficulty in practice because those assumptions are so strong,9 and hence so unlikely to 

correspond to reality. Dividends, earnings and prices are unlikely to grow at a constant 

rate literally forever. Two conditions are also well known to be necessary for the DCF 

approach to yield a reliable estimate of the cost of capital: the variant of the present 

value formula that is used must actually match the variations in investor expectations for 

the growth of dividends, and the growth rate(s) used in that formula must match current 

investor expectations. Less frequently noted conditions may also create problems. 

8 Why must the two growth rates be equal in a steady-growth DCF model? Think of earnings as divided 

between reinvestment, which funds future growth, and dividends. If dividends grow faster than earnings, 

there is less investment and slower growth each year. Sooner or later dividends will equal earnings. At that 

point, growth is zero because nothing is being reinvested (dividends are constant). If dividends grow slower 

than earnings, each year a bigger fraction of earnings are reinvested. That makes for ever faster growth. 

Both scenarios contradict the steady·growth assumption. So if you observe a company with different 

expectations for dividend and earnings growth, you know the company's stock price and its dividend growth 

forecast are inconsistent with the assumptions of the steady-growth DCF model. 

9 In this context "strong" means that the assumption is unlikely to match reality and that it also has a 

substantial impact on the model's results.



Appendix B 


Docket No. ERlO- -000 Page B-6 

1 Q6. Is estimating the "right" dividend growth rate the most difficult part for the 

2 

3 

4 

5 

6 

7 

8 

9 

A6. 

implementation of the DCF approach? 

Yes. Finding the right growth rate(s) is usually the "hard part" of a DCF application. 

The original approach to estimation of g relied on average historical growth rates in 

observable variables, such as dividends or earnings, or on the "sustainable growth" 

approach, which estimates g as the average book rate of return times the fraction of 

earnings retained within the finn. A major problem with using historical averages over 

periods with widely varying rates of inflation and costs of capital is that they are unlikely 

to equal current growth rate expectations. 

10 Q7. Specitying the current price is straightforward, but how does one specity the 

II 

12 A7. 

expected stream of dividends for use in the model? 

This is the most difficult and subjective part of implementing the DCF methodology. 

13 

14 

Several models exist to simplify the process, and these generally transfonn the problem 

of specitying a stream of dividends into one of specifying a set of expected dividend 

IS growth rates. These DCF models are then distinguished by how they model expected 

16 growth rates. The Commission's preferred DCF model is a modification of the simple 

17 DCF model that relies upon two different estimates of the long-tenn growth. It is 

18 described next. 

19 B. THE COMMISSION'SPREFERREDDCF METHOD 

20 Q8. What is the purpose of this section of the appendix? 

21 A8. In this section, I discuss the details of my implementation of the Commission-based DCF 

22 method based upon my interpretation of various Commission decisions.



Appendix B 

Docket No. ERIO-_-OOO 

EXHIBIT 

NO. SCE-IS 

Page B-7 

Q9. 

2 A9. 

3 

4 

5 

6 

7 

8 

9 

10 

II 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

Please describe the Commission's preferred DCF model. 

The Commission's 

preferred DCF model is a modification of the standard DCF model 

that uses a constant growth of dividends. 

pp. 61,262-63: 10 

The model is articulated in Opinion No. 445, at 

[n the past, we have consistently applied a one-step, constant growth DCF 

model for calculating ROEs for electric utilities. The DCF methodology 

determines the ROE by summing the dividend yield (with an adjustment 

for the quarterly payment of dividends) and expected growth rate. The 

resulting formula is DIP (I+.5g) + g = k, where "DIP" is the dividend 

yield, "g" is the sustainable growth rate of dividends per share, and "k" is 

the resulting ROE. The sustainable growth rate is calculated by the 

following formula: g = br + sv, where "b" is the expected retention ratio, 

"r" is the expected earned rate of return on common equity, "s" is the 

percent of common equity expected to be issued annually as new common 

stock, and "v" is the equity accretion rate. 

Thus, the Commission has specified the single-stage DCF model as being its preferred 

estimation method for electric utilities. 

The procedure has been used more recently by 

the Commission in Bangor Hydro and Midwest ISO, and its continued status as the 

Commission's preferred method is reaffirmed in Order No. 679 11 and Order No. 679-A. 12 

I disagree with the use of the 0.5 multiplier for the initial growth rate as a matter of 

economic principle because it violates the basic assumptions of the DCF model. 

Nonetheless, I present results of the Commission's 

DCF method as described in Opinion 

No. 445 because the Commission has specified this version of the single-stage DCF 

model as its preferred estimation method for electric utilities. 

However, I must note that 

this approach will tend to underestimate the true cost of capital, all else equal. 

10 The Commission also calculates growth rates using analysts' earnings growth forecasts from IIBIE/S, using 

the same procedure to adjust the dividend yield. I use analogous growth rate forecasts from Bloomberg 

termed their BEst forecasts. 

11 Promoting Transmission Investment Through Pricing Reform, Order No. 679, 71 Fed. Reg. 43,294 (July 31, 

2006), FERC Stats. & Regs. ~ 31,222, at PP 92, 102 (2006). 

12 Promoting Transmission Investment Through Pricing Reform, Order No. 679-A, 72 Fed. Reg. 1,152 (Jan. 

10, 2007), FERC Stats. & Regs. ~ 31,236, at P 63 (2006).



Appendix B 


QIO. Why do you disagree with the use of a 0.5 multiplier? 

EXHIBIT 

NO_ SCE-15 

Page B-8 

2 A I O. As shown in equations (B-1) and (B-2) above, the DCF model is derived under the 

3 

4 

5 

assumption that dividends grow at the full growth rate for the period. However, as stated 

in Opinion No. 445, the Commission's approach results in a variation ofthis fundamental 

result displayed in Equation (B-4): 

k 

Do x (1+ O.5g) 

= +g 

p 

(B-4) 

6 

7 

However, because it is the Commission's preferred method, I follow the Commission's 

precedent and use this version of the dividend yield in the DCF model. 

8 QIl. Opinion No. 445 also references sustainable growth. Please explain how the 

9 sustainable growth rate is determined. 

lOA II. Although companies can experience very high rates of growth from time to time (i.e., 

II 

12 

13 

14 

15 

16 

17 

18 

19 

greater than the growth of the economy as a whole), these high rates cannot generally be 

expected to last indefinitely. Conversely, very low rates of growth can generally be 

expected to improve over time. As implied by the name, the sustainable growth rate of a 

company is that which can be expected to be maintained by the company through 

reinvestment of its earnings or additional equity issuances at prices above book value. 

The growth achieved by reinvestment of new earnings depends on both the amount of 

earnings retained, b = (I - DividendslNet Income), and on the expected return on equity 

(r) those earnings will achieve. On the other hand, growth from new share issues 

depends on the percentage of new shares being issued, s, and the equity accretion ratio, 

20 

V= 1 1 ] . 

[ Market - to - Book Ratio 

Together, the implied sustainable growth rate is given as 

21 shown in Equation (5). 

g=br+sv 

(B-5)



AppendixB 


EXHIBIT 

NO. SCE-IS 

Page B-9 

QI2. 

2 

3 A12. 

4 

5 

6 Q13. 

7 A13. 

8 

9 

10 

II 

12 

13 

14 

IS 

16 

17 Q14. 

18 A14. 

19 

20 

21 

22 

23 

Is the sustainable growth rate the only growth rate you use in your implementatiou 

of the Commission's preferred DCF model? 

No. Consistent with the Commission's practice, I also estimate a version of the model 

where g is set equal to the long-term earnings growth rates provided by securities analysts. 

My source for security analysts' forecasts is Bloomberg through their BEst Estimates. 13 

How is the dividend yield determined? 

In the Commission-based methodology, Po is the stock price calculated as the average of 

the highest and lowest closing common stock price over the most recent six month period. 

In other words, the low dividend yield is the annualized current quarterly dividend, (i.e., 

the current dividend times 4), divided by the average of the highest closing prices over 

the most recent six months, and the high dividend yield is the annualized dividend 

divided by the average of the lowest closing prices over the most recent six months. The 

result of combining the high and low dividend yields with the two estimates of the 

dividend growth rate is four estimates of the cost of equity for each sample company. 

The highest (lowest) of the four estimates is reported as the high (low) estimate for the 

company which in tum are used to establish the range of reasonableness for the sample. 

How is the growth rate determined? 

The estimate of g is either the average long-term (5-year) analyst growth rate forecast or 

the sustainable growth rate as calculated in Equation (B-5) above where b is the expected 

retention ratio, r is the expected return on common equity, s is the expected growth in the 

number of common equity shares, and v is the accretion ratio. 

The procedure in the testimony of Commission staff witnesses Randolph A. 

Barlow l4 and Franklin D. KnightlS to implement the DCF model confirms that I 

13 BEst is Bloomberg's version of analyst forecasts comparable to l/B/E/S. 

14 Prepared Direct Answering Testimony of Commission Staff Witness Randolph A. Barlow, Pacific Gas and 

Electric Company, Dockets Nos. ER03-409-000, ER03-666-000, October 17,2003. 

15 Direct Testimony of Commission Staff Witness Franklin D. Knight, Allegheny Power, Docket No. ER02- 

136-004, November 25, 2002.


Direct Testimony of Michael J. ViIbert 

Appendix B 

Docket No. ER10- -000 


Page B-1O 

2 

3 

4 Q15. 

5 A15. 

6 

7 

8 

9 

10 

II 

12 

13 

14 

15 

16 Q16. 

17 A16. 

18 

19 

20 

21 

22 

23 

24 

have correctly interpreted the Commission's intention for implementation of the 

model. Both staff witnesses rely on Commission Opinion No. 445 and use the 

sustainable growth DCF as one of their estimation methods. 

Exactly how do you implement the Commission-derived DCF method? 

The Commission's DCF approach calculates a high and a low dividend yield, sustainable 

growth rates from Value Line information and uses lIB/E/S's long-term growth rates as 

an alternative source for growth rates. Because IIBIE/S long-term growth rates are no 

longer accessible for non-members of Thomson Financial, I use Bloomberg BEst 

estimates instead. In the New England RTO Rehearing Order, the Commission stated 

that it would not "preclude the presiding judge from finding candidates for inclusion in 

the proxy group for which comparable data can reasonably be substituted for the growth 

rate data reported by IIBIE/S or Value Line.,,16 Therefore, I calculate the sustainable 

growth rate for each sample company using methods that, to the best of my knowledge, 

are those recently relied upon by the Commission. I then determine the low, high and 

midpoint cost of equity estimates in accord with these procedures. 

Please explain your calculations in detail. 

I obtain recent dividend and stock price information from Bloomberg. I annualize the 

most recently announced dividends and calculate the high and low average stock prices 

over the most recent six months using monthly data.17 The high and low dividend yields 

are the annualized dividend divided by the average low and high stock price, respectively. 

Dividend yields for the sample companies calculated in this way are reported in 

Workpaper #7, Panel A and B to Table No.4, Exhibit No. SCE-16. 

To calculate the sustainable growth rate, I calculate each sample company's retention 

ratio, return on equity, expected growth in shares, and expected accretion ratio using 

16 See New England RTO Rehearing Order, at P 205. 

17 At the time of the analysis for this proceeding, the most recent six months period available in Bloomberg 

was November 2008 to April 2009.



AppendixB 


EXHIBIT NO. SeE-IS 

Page B-II 

2 

3 

4 

5 

6 

7 

8 

9 

10 

II 

Value Line infonnation. 18 The components of the sustainable growth rate are calculated 

as follows. 

Retention Ratio (b): I follow the calculation in Opinion No. 445 19 to detennine the 

retention ratio for each of the years, 2009, 2010, and 2013 20 and use the average for my 

calculations. (See Workpaper #2, Table No. MJV-4). 

Return on Equity (r): I again follow the calculation in Opinion No. 445. I calculate the 

return on equity for each of the years 2009, 2010, and 2012-2014 using Value Line's 

forecasted Earnings per Share ("EPS") and Book Value per Share ("BPS"). (See 

Workpaper #3, Table No. MJV-4). The average return on equity for the three 

years is adjusted using the formula provided in Opinion No. 445. 21 Thus, I 

multiply the average return on equity by the following adjustment factor: 

' D 2 x (I + Growth in Common Equity) 

Ad gustment ,.actor = ---'----------~--"-". 

2 + Growth in Common Equity 

(B-6) 

12 

13 

14 

15 

16 

17 

18 

19 

20 

The growth in common equity is calculated from the calculated common equity figures 

for 2009 and in 2013. The common equity for 2009 and 2013 are detennined as the 

common equity ratio for each year multiplied by the total capital for each corresponding 

year. Data on the forecasted common equity ratio and total capital are obtained from 

Value Line. (See Workpaper #4, Table No. MN-4) 

Growth in Shares (s): I have not been able to find a specification for the calculation of 

the external growth component ("s x v") of the sustainable growth rate in Opinion No. 

445. However, I am able to calculate the growth in common shares from Value Line 

infonnation on the expected number of shares outstanding in 2009 and in 2013.1 2 This 

18 Value Line information is from June 26, 2009, August 7, 2009, and August 28,2009. 

19 See Opinion No. 445, at 61,263. 

20 Value Line currently reports forecasts for the years 2009, 20 I0, and for the 2012-14 period. I treat the Value 

Line numbers reported for the 2012-14 period to be for the end of year 2013, the midpoint of the period. 

21 See Opinion No. 445, n.38. 

22 This calculation appears to be consistent with the calculation performed in Devon Power, LLC, 103 FERC ~ 

61,155 (2003) ("Devon Power").


Direct Testimony of Michael J. ViIbert 

AppendixB 

Docket No. ERlO- -000 


Page B-12 

figure is multiplied by the current price-to-book ratio to obtain S?3 (See Workpaper #5, 

2 

3 

4 

5 

6 

7 

Table No. MN-4) 

Accretion Ratio (v): Opinion No. 445 does not specify the calculation of the accretion 

ratio, but the use of current data appears to be consistent with prior Commission 

practice. 24 The method uses Value Line information to calculate the accretion ratio as {I 

- [I / (Current Stock Price/Current Book Value)]} using Value Line's 2009 data. 25 (See 

Workpaper #6, Table No. MN-4) 

8 Q17. How do you use the sustainable growth rates described above and the long-term 

9 

10 

growth rate forecasts to determine the sample companies' Commission-based DCF 

cost of equity? 

II A17. I calculate each sample company's Commission-based DCF cost of equity, k, using the 

12 

13 

formula in Equation (B-2): k = (Do/Po) x (l + .5g) + g. For each company I calculate the 

cost of equity letting g take on either the BEst long-term growth rate forecasts or the 

14 sustainable growth rate calculated above. 26 I then determine the highest and lowest 

15 estimate that results using either the sustainable or BEst growth rate and high or low 

16 dividend yields, following the Commission's clarification in Midwest ISO. 27 In 

17 

18 

determining the lowest estimate, I discard any cost of equity estimate that is below the 

six-month average yield on bonds corresponding to a comparable rating to the company's 

19 bond rating plus 100 basis points. This procedure is consistent with Commission 

20 precedent in several proceedings including Bangor Hydro, New England RTO Rehearing 

23 See Devon Power. 

24 The Devon Power Order appears to rely on a weighted average of the book value for the past and current 

year plus current price data. Also, in City of Vernon, California, Docket No. ELOO-I05-007, Docket No. 

EROO-2019-007, Prepared Direct and Answering Testimony of Staff Witness Douglas M. Green, July 16, 

2004 ("Green Testimony"), witness Green states on p. 29 that he used "the company's recent price-to-book 

ratio. " 

25 Note that, consistent with Commission documents, I present the external growth components, s x v, as s ~ 

(growth in shares) x (Price per Share/BPS) and v ~ [I - BPS/ (Price per Share)]. 

26 BEst estimates are taken as of September 11,2009. 

27 See Midwest ISO, PP 18, 21.



AppendixB 

Docket No. ERIO· ·000 

EXHIBIT NO. seE-IS 

Page B·13 

Order and Southern California Edison?8 This data then allows me to detennine a range 

2 

3 

4 Q18. 

5 

6 A18. 

7 

8 

9 

10 

II 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

of reasonable returns as the range between the lowest and the highest ROE of all sample 

companIes. 

How do you use the sample companies' high and low computed ROEs to arrive at 

an estimate of the cost of equity? 

I first detennine a range of reasonable returns as the range between the lowest and the 

highest ROE of all sample companies, computed as described above. 

median, the midpoint and the mean of the range of reasonable returns. 

I then compute the 

In its decisions 

regarding the cost of equity for electric transmission companies, the Commission has 

until recently consistently relied on the midpoint of the range of reasonable returns. 

use of the midpoint is specifically mentioned and affinned by the Commission in, among 

others, Midwest ISO, New England RTO Rehearing Order, and Bangor Hydro. 29 

Moreover, in Consumers Energy,30the Commission specifically rejected and reversed the 

use of the sample median as an alternative estimate, relying on the precedent set in 

Opinion Nos. 445 and 446. 31 

Acknowledging the fact that the median is frequently used in rate proceedings for 

regulated gas utilities, the Commission has nonetheless neither accepted nor required the 

use of the median in rate proceedings for electric utilities. In Order No. 679-A, the 

Commission stated: 

We agree with TAPS that averaging each company's low and high DCF 

return would result in a single average DCF result for each electric 

company, making it like the single DCF return for gas and oil pipelines, 

from which a median return on equity for the group can be calculated. 

While this is an acceptable method, we will not require use of that method 

in the Commission's DCF analysis because that issue is beyond the scope 

The 

28 Southern California Edison at p. 61,266. 

29 See Midwest ISO, at P 30, New England RTO Rehearing Order, at P 203, Bangor Hydro, at P 14. 

30 Consumers Energy Co., 98 FERC '1161,333, at 62,416 (2002) (Opinion No. 456) ("Consumers Energy"). 

31 System Energy Resources, lnc., 92 FERC '1161,119 (2000) (Opinion No. 446) ("Systems Energy").



Appendix B 


EXHIBIT NO_ SeE-1S 

Page B-14 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

II 

of this proceeding and is more appropriately addressed in the individual 

application proceedings. 32 

However, in its Golden Spread decision,3l the FERC seemingly altered course towards 

favoring the median and held that: 

When deriving the ROE for an individual utility facing average risk, the 

Commission has held that the median best represents the central tendency 

in a proxy group with a skewed distribution of returns. 

As noted in my testimony, however, the Commission's 

decision in PSE&G, issued 

September 30, 2008, seemed to suggest that it had reverted back towards its earlier 

preference for the midpoint. 

allowed return based upon the midpoint. 34 

In that decision, without comment, the Commission set the 

32 See Order No. 679-A, at P 63 n.1 05. 

33 Golden Spread Electric Cooperative Inc., 123 FERC 1161,047 (2008) (Opinion No. 50 I), ("Golden Spread') 

April 21, 2008. 

34 In the PSE&G decision, the Commission accepted my recommend ROE which was based upon the midpoint 

of the sample, but the Commission did not otherwise comment on the relevance of the midpoint or the 

median.



DOCKET 

EXHIBIT 

ERIO-_-OOO 

NO. SCE-16 

MICHAEL J. VILBERT WORKPAPERS


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TableNo. MJV-l 

Index to Tables for the Testimony of Michael J. Vilbert 

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Table No. MJV-2 



Commission-Based Electric Sample 



Company Information 

Capital Structure Information 

DCF Cost of Equity 

Page 1


Commission Based Electric Sample 

Company Information 

S&P Business Revenue for 2008 2nd Quarter, 2009 Bond 

Company Profile ($ in millions) Rating 

[I) [2) [3) 

American Electric Power Co Inc Excellent 14,440 BBB 

Cleco Corp Strong 1,080 BBB 

Empire District Electric ColThe Strong 518 BBB- 

Entergy Corp Strong 13,094 BBB 

OGE Energy Corp Strong 4,071 BBB+ 

Centerpoint Energy Inc Excellent 11,322 BBB 

Progress Energy Inc Excellent 9,167 BBB+ 

Dominion Resources Inc/V A Excellent 16,290 A- 

FPL Group Inc Excellent 16,410 A 

SCANACorp Excellent 5,319 BBB 

Southern Co Excellent 17,127 A 

TECO Energy Inc Excellent 3,375 BBB 

Duke Energy Corp Excellent 13,207 A- 

Xcel Energy Inc Excellent 11,203 BBB+ 


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[I): Issuer Ranking: U.S. Regulated Electric Utilities, Standard & Poor's, RatingsDirect, August 2009. 

[2)- [3): Historical Bloomberg data accessed September 11,2009. 

Page 2


:;;::;;::;;: 

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EXHIBIT NO. SCE-I6 


Panel A: Commission-Based Unrestricted Electric Sample 

Summary of High, Low and Median Cost of Equity Estimates 

Companies Meeting Sample Screening Criteria 


6_MQnth Dividend Yield Adjusted Dividend Yield Grov.rthRates Implied Cost of Equity 

Company Bond Rating High Low High Low High Low High Low 

[t) [2) [3) [4) [5) [6) [7) [8) [9) 

American Electric Power Co Inc BBB 5.92% 5,55% 6.07% 5.68% 5.00% 4.81% 11.07% \0.49% 

Cleco Corp BBB 4.10% 3.85% 4.35% 3.95% 11.82% 4.81% 16.16% 8,76% 

Empire District Electric Co/The • BSB- 7.87% 7.39% 9.21% 7,50% 34.00% l.8ID/':' 43.21% 10.30% 

Entergy Corp BBB 4.17% 3,87% 4.34% 3,99% 8.25% 6.33% 12.59% 10.33% 

aGE Energy Corp BBB+ 523% 4.88% 5,39% 5.00% 6,32% 5.00% 11.71% 10.00% 

Centerpoint Energy Inc BBB 7.04% 6.48% 7.28% 6.70% 7.00% 6.62% 14.28% 13.32% 

Progress Energy Inc BBB+ 6.88% 6.50% 7.06% 6.59% 5.42% 2.51% 12.48% 9.09% 

Dominion Resources Inc/VA A· 5.54% 5.28% 5.77% 5.42% 7.99% 5.33% 13.75% 10.75% 

FPL Group Inc A 3.52% 3.29% 3.68% 3.44% 9.05% 8.80% 12.73'% 12.23% 

SCANACorp BBB 5.99% 5.64% 6.14% 5.77% 4.91% 4.66% 11.05% 10.43% 

Southern Co A 5.92% 5.58% 6.07% 5.70% 5.25% 4.31% 11.32% 1000% 

TECO Energy Inc BBB 6.86% 6.30% 7.05% 6.42% 5.50% 3.62% 12.55% 10.04% 

Duke Energy Corp A- 6.71% 6.39% 6.82% 644% 3.38% 1.28% 10.20% 7.72% 

Xce1 Energy Inc BBB+ 5.39% 5.10% 5.54% 5.20% 5.50% 4.06% 11.04% 9.26% 

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Range 16.16% 7.72% 

Midpoint 11.94% 

Median 11.04% 

Mean 11.28% 

Number of companies meet screening criteria 14 

Number of companies included in the calculation of Implied Cost of Equity 13 

Sources 

and Notes 

[I]: Table No. MJV-2, [3] 

[2]: Workpaper #7 to Table No. MJV-4, Panel 8, [4]. 

[3) Workpaper #7 to Table No. MIV-4, Panel A, [4] 

[4) [2) x ( 1 +5 x [6) ). 

[5) [3)x( 1 +5x[7)) 

[6]: Highest Growth Rate from Workpaper #1 to Table No. MJV-4, [7] and Workpaper #10 to Table No. MJV-4, [l]. 

[7]: Lowest Growth Rate from Workpaper #1 to Table No. MJV-4 [7] and Workpaper#1O to Table No MJV-4, [IJ. 

[8) [4) + [6). 

[9) [5) + [7) . 

• Companies which were excluded either because their growth rate is above 13.3% or estimated cost of equity is below cost of debt plus 100 bps (excluded numbers are bold and italicized). These 

companies are not included in the calculation of Median and Mean. 

Page 4

Table No. MJV·4 

Panel B Commission·Based Restricted Electric Sample 

Summary of High, Low and Median Cost of Equity Estimates 

Companies Meeting Sample Screening Criteria 


6-Month Dividend Yield Adiusted Dividend Yield Growth Rates 

Company Bond Rating High Low High Low High Low 

[I] [2] 13] [4] [5] [6] [7] 

American Electric Power Co Inc BBB 5.92% 5.55% 6.07% 5.68% 5.00% 4.81% 

Cleco Corp BBB 4.10% 385% 4.35% 3.95% 11.82% 4.81% 

Empire District Electric ColThe • BBB· 7.87% 7.39% 9.21% 7.50% ~ 2.81% 

Entergy Corp BBB 4.17% 3.87% 4.34% 3.99% 8.25% 6.33% 

aGE Energy Corp BBB+ 5.23% 4.88% 5.39% 5.00% 6.32% 5.00% 

Centerpoint Energy Inc BBB 7.04% 6.48% 7.28% 6.70% 7.00% 6.62% 

Progress Energy Inc BBB+ 6.88% 650% 706% 6.59% 5.42% 2.51% 

Dominion Resources Inc/V A 

FPL Group Inc 

SCANA Corp BBB 5.99% 5.64% 6.14% 5.77% 4.91% 4.66% 

Southern Co 

TECa Energy Inc BBB 6.86% 6.30% 7.05% 6.42% 5.50% 3.62% 

Duke Energy Corp 

Xcel Energy Inc BBB+ 5.39% 5.10% 5.54% 5.20% 5.50% 4.06% 

Range 

Midpoint 

Median 

Mean 

Number of companies meet screening criteria 

Number of companies included in the calculation of Implied Cost of Equity 


Implied 

High 

Cost of Equity 

Low 

[8] [9] 

11.07% 10.49% 

16.16% 8.76% 

43.21% 10.30% 

12.59% 10.33% 

11,71% 10,00% 

14.28% 13.32% 

12.48% 9,09% 

11.05% 10.43% 

12,55% 10.04% 

1\.04% 9.26% 

- 

16,16% 8.76% 

12.46% 

11.04% 

11.37% 

10 

9 

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Sources 

and Notes: 

[1]: Table No. MJV-2, [3] 

[2]: Workpaper #7 to Table No. MJV-4, Panel B, [4] 

[3]: Workpaper #7 to Table No. MJV-4, Panel A, [4] 

[4] [2] x ( 1+.5 x [6]) 

[5] [3] x ( I + .5 x [7] ) 

[6] Highest Grov.th Rate from Workpaper #1 to Table No. MJV-4, [7] and Workpaper #10 to Table No, MJV.4, [lJ 

[7] Lowest Grov.th Rate from Workpaper #1 to Table No. MJV-4 [7) and Workpaper #10 to Table No. MJV-4, [I] 

[8] [4] + [6]. 

[9] [5] + [7] 

.. Companies which were excluded either because their growth rate is above 13.3%, estimated cost of equity is below cost of debt plus ]00 bps, or their debt rating is not within one notch (+1.) ofBBB 

(excluded numbers are bold and italicized), These companies are not included in the calculation of Median and Mean 

Page 5

Workpaper #1 to Table No. MJV-4 


Sustainable Growth Rate 

EXHIBIT 

NO. SCE-16 

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Company 

American Electric Power Co Inc 

Cleco Corp 

Empire District Electric Coffhe 

Entergy Corp 

OGE Energy Corp 

Centerpoint Energy Inc 

Progress Energy Inc 

Dominion Resources IneN A 

FPL Group Inc 

SCANA Corp 

Southern Co 

TECO Energy Inc 


Xcel Energy Inc 

Expected Average Average Return on Adjustment 

Retention Ratio (b) Equity Factor 

[I] [2] [3] 

44.28% 10.49% 1.03 

43.39% 9.94% 1.03 

24.04% 10.62% 1.03 

54.20% 14.59% 1.04 

45.60% 11.58% 1.05 

32.24% 16.58% 1.05 

23.99% 9.77% 1.02 

45.11% 15.49% 1.05 

56.99% 13.41% 1.05 

36.68% 10.54% 1.04 

27.71% 13.12% 1.03 

29.99% 11.39% 1.03 

18.10% 7.21% 1.01 

39.28% 9.89% 1.03 

Adjusted Average Accretion Ratio Sustainable 

Return on Equity (r) (s) (v) Growth Rate 

[4] [5] [6] [7] 

10.78% 0.72% 4.63% 4.81% 

10.29% 1.92% 18.06% 4.81% 

10.91% 2.96% 6.18% 2.81% 

15.22% 0.00% 42.48% 8.25% 

12.12% 3.30% 23.91% 6.32% 

17.40% 2.33% 43.16% 6.62% 

9.98% 0.82% 13.89% 2.51% 

16.20% 1.75% 38.82% 7.99% 

14.04% 1.80% 44.11% 8.80% 

10.97% 3.90% 16.38% 4.66% 

13.46% 1.41% 40.78% 4.31% 

11.69% 0.58% 20.35% 3.62% 

7.26% 0.25% -13.57% 1.28% 

10.13% 0.51% 15.00% 4.06% 

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[I]: Workpaper #2 to Table No. MlV-4, [10]. 

[2]: Workpaper #3 to Table No. MJV-4, [10]. 


[4]: [2] x [3]. 



[7]: [I] x [4] + [5] x [6]. 

Page 6

Workpaper 

Commission 

#2 to Table No. MJV-4 

Based Electric Sample 

Calculation of Retention Ratio 


EPS Fiscal EPS Fiscal Forecasted Forecasted Retention 

Year 2009 Year 2010 EPS 2012- Annualized Annualized Forecasted Annualized Retention Retention Ratio, 2012 - Expected Average 

Company Estimate Estimate 2014 Estimate Dividends - 2010 Dividends - 201 Dividends - 2012 - 2014 Ratio, 2009 Ratio,2010 2014 Retention Ratio 

[1J I2J [3J [4J [5J [6J [7J [8J [9J [IOJ 

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American Electric Power Co Inc 2.85 300 3.50 1.64 1.66 1.90 42.46% 44.67% 45.71% 44.28% 

Cleco Corp 1.65 1.95 2,50 0.90 100 1.60 45.45% 48.72% 36.00% 43.39% 

Empire District Electric ColThe 1.55 1.70 2.00 128 128 140 17.42% 2471% 3000% 2404% 

Entergy Corp 6.60 7.20 8.00 3.00 3,20 3.80 54.55% 55.56% 52.50% 54,20% 

OGE Energy Corp 2.45 2.70 3,25 1.43 1.46 1.65 41.63% 45.93% 49.23% 45,60% 

Centerpoint Energy Inc 1.05 1.15 1.50 0.76 0.80 0.92 27.62% 30.43% 38.67% 32,24% 

Progress Energy Inc 3,10 3.25 3.60 2.48 2.50 2.56 20.00% 23.08% 28.89% 23,99% 

Dominion Resources InclV A 3,25 3.35 4.00 1.75 1.87 2.20 46.15% 44,18% 45,00% 45,11% 

FPL Group Inc 415 4.80 5.50 1.89 2.00 2.30 54.46% 58,33% 58,18% 56,99% 

SCANA Corp 285 3,00 3.50 1.88 1.92 2.10 34.04% 36,00% 40,00% 36.68% 

Southern Co 2.30 2.40 3.00 1.73 1.80 2.00 24.78% 25,00% 33.33% 27.71% 

TECQ Energy Inc 1.05 1.15 1.40 0.80 0.80 0.90 23.81% 30.43% 35,71% 29.99% 

Duke Energy Corp LlO 1.20 1.40 0,94 0.98 1.10 14.55% 18.33% 21.43% 18.10% 

Xcel Energy Inc LSO 1.60 2.00 0,97 1.00 1.10 35.33% 37.50% 45.00% 39.28% 

Sources 

and Notes 

[1]- [6]: Most recent Value Line Standard Edition dated as of June 26, 2009, August 7, 2009, and August 28, 2009 

[7J([lJ-[4J)I[I]. 

[8] ([2J - [5J) 1 [2J 

[9] ( [3J - [6J ) 1 [3J. 

[10]: Average of[7] through [9]. 

Page 7

Workpaper 

Commission 

Calculation 

#3 to Table No. MJV-4 

Based Electric Sample 

of Return on Equity 


EPS Fiscal Year EPS Fiscal Year EPS 2012 - 2014 Book Value Per Book Value Per Book Value Per Share· Return on Equity. Return on Return on Equity, Average Return on 

Company 2009 Estimate 2010 Estimate Estimate Share - 2009 Share - 2010 2012 - 2014 200. Equity, 2010 2012 - 2014 Equity 

(IJ (2J (3J (4J (5J (6J (7J (8J (9J [10] 

American Electric Power Co Inc 2.85 3.00 3 ..50 27.30 28.60 33.25 10.44% 10.49% 10,53% 10.49";" 

Cleco Corp 1.65 1.95 2.50 18.55 19.60 22.75 8.89% 9.95% 10,99% 9.94% 

Empire District Electric ColThe 1.55 1.70 2.00 15,75 16.05 17.50 9.84% 10,59% 11,41% 10,62% 

Entergy Corp 6,60 7.20 8.00 4).00 47.25 60.75 15.35% 15.24% \3.17'% 14,59";;' 

OGE Energy Corp 2.45 2.70 3.25 21.40 22.90 28.25 11.45% 11.79% 11.50% 11.58% 

Centerpoint Energy Inc 1.05 1.15 1.50 6.40 6.90 9.00 16.41% 16.67% 16.67% 16.58% 

Progress Energy Inc 3.10 3.25 3.60 31.95 33.05 36.80 9.70% 9.83% 9.78% 9.77% 

Dominion Resources Inc/VA 3.25 3.35 4.00 19.80 21.60 27.50 16.41% 15.51% 14.55% 15.49% 

FPL Group Inc 4.15 4.80 5.50 31.05 33.95 43.25 13.37'% 14.14% 12.72% 13.41% 

SCANA Corp 2.85 3.00 3.50 27.05 28.45 33.25 10.54% 10.54% 10.53% 10.54% 

Southern Co 2.30 2.40 3.00 18.05 18.95 21.50 12.74% 12.66% 13.95% 13.12% 

TECD Energy Inc 1.05 LIS 1.40 9.70 10.05 11.75 10.82% 11.44% 11.91% 11.39% 

Duke Energy Corp 1.10 1.20 1.40 16.65 16.85 17.75 6.61% 7.12% 7.89% 7.21% 

Xed Energy Inc 1.50 1.60 2.00 15.90 16.50 19.00 9.43% 9.70% 10.53% 9.89% 

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[1]- [6]: Most recent Value Line Standard Edition dated as of June 26, 2009, August 7, 2009, and August 28, 2009 

[7]: [1]1 [4]. 

(8J (2J I (5J 

(9J (3J I (6J 

[10]: Average of(7J through [9]. 

Page 8



Calculation of Return On Equity Adjustment Factor 


Common Equity Common Equity Total Capital- Total Capital - Common Common Equity, Growth in Common Adjustment 

Company Ratio - 2009 Ratio - 2012 - 2014 2009 2012 - 2014 Equity, 2009 2012 - 2014 Equity Factor 

[IJ [2J [3J [4J [5J [6J [7J [8J 

American Electric Power Co Inc 0.46 0.48 28,175 34,200 12,961 16,245 5.81% 103 

Cleco Corp 0.47 0.54 2.400 2.750 1,128 1.485 7.12% 103 

Empire District Electric Corrhe 0.44 0.49 1,250 1,375 544 674 5.51% 103 

Entergy Corp 0.39 0.39 21,000 29,800 8.085 11,473 9.14% 104 

OGE Energy Corp 0.50 0.48 4,120 6,300 2.060 2,993 9.78% 105 

Centerpoint Energy Inc 0.19 0.30 12,650 11,800 2,340 3,481 10.44% 105 

Progress Energy Inc 0.45 0.48 19,840 22,300 8,928 10,593 4.37% 102 

Dominion Resources IncN A 0.43 0.47 27,450 36,300 11,804 17,061 9.65% 105 

FPL Group Inc 0.46 0.46 28,375 41,400 12,911 18,837 9.90% 105 

SCANA Corp 0.41 0.43 8,310 10.850 3.366 4,666 8.51% 104 

Southern Co 0.43 0.42 33,775 42,000 14,354 17,640 5.29% 103 

TEeO Energy Inc 0.40 0.42 5,275 6,175 2,084 2,563 5.31% 103 

Duke Energy Corp 0.60 0.52 36,300 44,300 21,599 23,036 1.62% 101 

Xcel Energy Inc 0.48 0.49 15,275 18,300 7,256 8,876 5.17% 103 

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[I] - [4J: Most recent Value Line Standard Edition dated as of June 26, 2009, August 7, 2009, and August 28,2009. 

[5] [lJ x [3J. 

[6] [2J x [4). 

[7] ([6J / [5J) A (1/4) - I. 

[8] (2 x ( 1+ [7J» / (2 + [7J ) See FERC Opinion No. 445, footnote 38. 

Page 9



Calculation of Expected Growth in Shares 

Common Shares Common Shares Outstanding M Expected Growth in 

Company Outstanding - 2009 2012-2014 Shares (s) 

[I] [2] [3] [4] 

American Electric Power Co Inc 476.76 490.00 0.69% 0.72% 

Cleco Corp 62.00 66.00 1.58% 1.92% 

Empire District Electric Co/The 34.50 38.50 2.78% 2.96% 

Entergy Corp 188.00 188.00 0.00% 0.00% 

OGE Energy Corp 96.00 106.00 2.51% 3.30% 

Centerpoint Energy Inc 370.00 390.00 1.32% 2.33% 

Progress Energy Inc 280.00 288.00 0.71% 0.82% 

Dominion Resources Jnc/V A 597.00 623.00 1.07% 1.75% 

FPL Group Inc 415.00 432.00 1.01% 1.80% 

SCANACorp 124.00 141.00 3.26% 3.90% 

Southern Co 796.00 823.00 0.84% 1.41% 

TECO Energy Inc 214.00 218.00 0.46% 0.58% 

Duke Energy Corp 1295.00 1310.00 0.29% 0.25% 

Xcel Energy Inc 456.00 464.00 0.44% 0.51% 


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[1]- [2]: Most recent Value Line Standard Edition dated as of June 26. 2009. August 7, 2009, and August 28, 2009. 

[3]: ([2] 1 [1]) A (1/4) - I. 

[4]: [3] x ([3], from Workpaper #6 to Table No. MJV-4 ). 

Page 10

Company 


Cleco Corp 

Empire District Electric ColThe 

Entergy Corp 




Dominion Resources Ine/V A 

FPL Group Inc 

SCANACorp 

Southern Co 






Calculation of Accretion Ratio 

FERC Average Price - Book Value Per 

High and Low Share - 2009 

[1] [2] 

28.63 27.30 

22.64 18.55 

16.79 15.75 

74.76 43.00 

28.13 21.40 

11.26 6.40 

37.10 31.95 

32.36 19.80 

55.56 31.05 

32.35 27.05 

30.48 18.05 

12.18 9.70 

14.66 16.65 

18.71 15.90 

Market-to- Accretion Ratio 

Book Ratio (v) 

[3] [4] 

1.05 4.63% 

1.22 18.06% 

1.07 6.18% 

1.74 42.48% 

1.31 23.91% 

1.76 43.16% 

1.16 13.89% 

1.63 38.82% 

1.79 44.11% 

1.20 16.38% 

1.69 40.78% 

1.26 20.35% 

0.88 -13.57% 

1.18 15.00% 


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[1]: Workpaper #8 to Table No. MJV-4, Panel C, [7]. 

[2]: Most recent Value Line Standard Edition dated as of June 26, 2009, August 7, 2009, and August 28, 2009. 

[3]: [1]1 [2]. 

[4]: 1-( I 1[3]). 

Page 1I



Panel A: Calculation of Dividend Yields using High Prices 

Average High Current Annualized Low Dividend 

Company Stock Price Dividend Dividend Yield 

[I] [2] [3] [4] 

American Electric Power Co Inc $29.56 $0.41 $1.64 5.55% 

Cleco Corp $23.35 $0.23 $0.90 3.85% 

Empire District Electric ColThe $17.31 $0.32 $1.28 7.39% 

Entergy Corp $77.49 $0.75 $3.00 3.87% 

OGE Energy Corp $29.09 $0.36 $1.42 4.88% 

Centerpoint Energy Inc $11.72 $0.19 $0.76 6.48% 

Progress Energy Inc $38.13 $0.62 $2.48 6.50% 

Dominion Resources IncN A $33.16 $0.44 $1.75 5.28% 

FPL Group Inc $57.44 $0.47 $1.89 3.29% 

SCANA Corp $33.34 $0.47 $1.88 5.64% 

Southern Co $31.38 $0.44 $1.75 5.58% 

TECO Energy Inc $12.70 $0.20 $0.80 6.30% 

Duke Energy Corp $15.01 $0.24 $0.96 6.39% 

Xcel Energy Inc $19.23 $0.25 $0.98 5.10% 


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[I]: Workpaper #8 to Table No. MJV-4, Panel A, [7]. 

[2]: Workpaper #9 to Table No. MJV-4. 

[3]: [2] x 4. 

[4]: [3]/[1]. 

Page 12



Panel B: Calculation of Dividend Yields using Low Prices 

Average Low Current Annualized High Dividend 

Company Stock Price Dividend Dividend Yield 

[I] [2] [3] [4] 

American Electric Power Co Inc $27.69 $0.41 $1.64 5.92% 

Cleco Corp $21.93 $0.23 $0.90 4.10% 

Empire District Electric ColThe $16.27 $0.32 $1.28 7.87% 

Entergy Corp $72.02 $0.75 $3.00 4.17% 

OGE Energy Corp $27.16 $0.36 $1.42 5.23% 

Centerpoint Energy Inc $10.80 $0.19 $0.76 7.04% 

Progress Energy Inc $36.07 $0.62 $2.48 6.88% 

Dominion Resources Inc/V A $31.56 $0.44 $1.75 5.54% 

FPL Group Inc $53.68 $0.47 $1.89 3.52% 

SCANA Corp $31.36 $0.47 $1.88 5.99% 

Southern Co $29.58 $0.44 $1.75 5.92% 

TECO Energy Inc $11.66 $0.20 $0.80 6.86% 

Duke Energy Corp $14.31 $0.24 $0.96 6.71% 

Xcel Energy Inc $18.18 $0.25 $0.98 5.39% 

- 


[I]: Workpaper #8 to Table No. MJV-4, Panel B, [7]. 

[2]: Workpaper #9 to Table No. MJV-4. 

[3]: [2] x 4. 

[4]: [3] / [1]. 

EXHIBIT NO. SCE- I6 

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Panel A: Maximum Closing Prices 

Company Sep-09 Aug-09 Jul-09 Jun-09 May-09 Apr-09 Average 

[I] [2] [3] [4] [5] [6] [7] 

American Electric Power Co Inc $31.07 $31.86 $31.14 $29.04 $26.94 $27.33 $29.56 

Cleco Corp $24.47 $24.97 $24.02 $22.57 $21.41 $22.64 $23.35 

Empire District Electric Co/The $18.37 $18.76 $18.62 $16.59 $16.25 $15.27 $17.31 

Entergy Corp $79.58 $81.79 $80.96 $78.24 $74.75 $69.64 $77.49 

OGE Energy Corp $31.50 $32.16 $30.29 $28.37 $26.53 $25.71 $29.09 

Centerpoint Energy Inc $12.45 $12.83 $12.05 $11.24 $11.01 $10.74 $11.72 

Progress Energy Inc $39.37 $39.70 $39.85 $38. \3 $35.77 $35.98 $38.13 

Dominion Resources IncN A $33.08 $34.44 $34.80 $33.87 $31.99 $30.79 $33.16 

FPL Group Inc $55.98 $58.17 $60.05 $58.20 $57.96 $54.27 $57.44 

SCANA Corp $34.74 $34.95 $35.80 $32.59 $30.85 $31.08 $33.34 

Southern Co $31.44 $31.63 $32.63 $31.90 $29.27 $31.38 $31.38 

TECO Energy Inc $13.44 $13.68 $13.49 $12.04 $12.20 $11.33 $12.70 

Duke Energy Corp $15.52 $15.70 $15.53 $14.67 $14.40 $14.26 $15.01 

Xcel Energy Inc $19.68 $19.95 $20.10 $18.44 $18.39 $18.81 $19.23 

- 


[1]- [6]: Historical Bloomberg data accessed September II, 2009. 

[7]: Average of[I]- [6]. 

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Page 14



Panel B: Minimum Closing Prices 


Company Sep-09 Aug-09 Jul-09 Jun-09 May-09 Apr-09 Average 

[I] [2] [3] [4] [5] [6] [7] 

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Cleco Corp $24.03 $23.85 $21.75 $20.76 $20.09 $21.09 $21.93 


Entergy Corp $77.69 $77.37 $72.71 $73.46 $66.90 $63.98 $72.02 



Progress Energy Inc $38.69 $38.44 $36.19 $35.27 $34.07 $33.77 $36.07 

Dominion Resources Inc/VA $32.74 $33.08 $32.45 $31.76 $30.33 $29.01 $31.56 

FPL Group Inc $53.42 $56.18 $54.14 $55.05 $53.06 $50.20 $53.68 


Southern Co $31.03 $30.89 $30.70 $28.63 $27.36 $28.88 $29.58 

TECO Energy Inc $13.10 $12.95 $11.27 $11.38 $10.83 $1Q.43 $11.66 



= 


[1]- [6]: Historical Bloomberg data accessed September 11,2009. 

[7]: Average of[I]- [6]. 

Page 15



Panel C: Average of Maximum and Minimum Closing Prices 

EXHIBIT NO. SCE- I6 

Company Sep-09 Aug-09 1ul-09 1un-09 May-09 Apr-09 Average 

[I] [2] [3] [4] [5] [6] [7] 

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Cleco Corp $24.25 $24.41 $22.89 $21.67 $20.75 $21.87 $22.64 


Entergy Corp $78.64 $79.58 $76.84 $75.85 $70.83 $66.81 $74.76 



Progress Energy Inc $39.03 $39.07 $38.02 $36.70 $34.92 $34.88 $37.10 

Dominion Resources IncN A $32.91 $33.76 $33.63 $32.82 $31.16 $29.90 $32.36 

FPL Group Inc $54.70 $57.18 $57.10 $56.63 $55.51 $52.24 $55.56 


Southern Co $31.24 $31.26 $31.67 $30.27 $28.32 $30.13 $30.48 

TECO Energy Inc $13.27 $13.32 $12.38 $11.71 $11.52 $10.88 $12.18 




[1] - [6]: Average of Work paper #8 to Table No. MJV-4, Panels A and B. 

[7]: Average of[1] - [6]. 

Page 16

Company 



Most Recent Dividend Payments 

Most Recent Dividend 


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CIeco Corp 

Empire District Electric Co/The 

Entergy Corp 




Dominion Resources IncN A 

FPL Group Inc 

SCANA Corp 

Southern Co 




$0.41 

$0.23 

$0.32 

$0.75 

$0.36 

$0.19 

$0.62 

$0.44 

$0.47 

$0.47 

$0.44 

$0.20 

$0.24 

$0.25 


Historical Bloomberg data accessed September I I, 2009. 

Page 17



BEst Information 

Long Term Growth Number of 

Company Forecasts Analysts 

[I] [2] 

American Electric Power Co Inc 5.0% 3 

Cleco Corp 11.8% 3 

Empire District Electric ColThe 34.0% 

Entergy Corp 6.3% 3 

OGE Energy Corp 5.0% 

Centerpoint Energy Inc 7.0% 

Progress Energy Inc 5.4% 6 

Dominion Resources IneN A 5.3% 3 

FPL Group Inc 9.1% 6 

SCANACorp 4.9% 3 

Southern Co 5.3% 4 

TECO Energy Inc 5.5% 2 

Duke Energy Corp 3.4% 4 

Xcel Energy Inc 5.5% 4 


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[1]- [2]: Bloomberg growth as of September II, 2009. 

Long-term growth rates are the mean of the analysts forecasts. 

Page 18

Date 

Workpaper 

# 11 to Table No. MJV-4 


Public Utility Bond Yield Summary 

Moody's Public Utility Bond 

Rating A Yield 

Moody's Public Utility Bond Rating 

BBB Yield 


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Apr-09 

May-09 

Jun-09 

Jul-09 

Aug-09 

Sep-09 

Average Yield 

6.09 

5.66 

5.95 

6.16 

6.48 

6.49 

6.14 

7.25 

6.30 

6.81 

7.23 

7.75 

8.02 

7.23 


Historical Bloomberg data accessed September 11,2009 (Monthly Averages). 

Page 19

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