Exhibit 99.2
SCANA CORPORATION
Moderator: John Winn
October 24, 2003
9:00 am CT
Operator: Good morning ladies and gentlemen. Thank you for standing
by. My name is (Amy) and I will be your conference
facilitator today. At this time I would like to welcome
everyone to the Scana Corporation conference call. All
lines have been placed on mute to prevent any background
noise.
After the speakers' remarks there will be a question and
answer period. At that time if you would like to ask a
question, simply press Star then the number 1 on your
telephone keypad. If you would like to withdraw your
question, press Star then the number 2.
As a reminder this conference call is being recorded on
October 24, 2003. Anyone who does not consent to the
taping may drop off the line at this time.
I would now like to turn the call over to John Winn,
Director of Investor Relations and Chairholder Services.
John Winn: Thank you (Amy) and good morning. I'd like to welcome
everyone to our third quarter earnings conference call,
including those who are joining us on the Web broadcast
over the Internet.
Earlier this morning we issued a press release announcing
comparative financial results for the third quarter and
first nine months of 2003. In just a minute Kevin Marsh,
Scana's Senior Vice President and Chief Financial Officer,
will review those results and respond to questions.
Before I turn the call over to Kevin I do have several
administrative items to review. Those of you who are on
our mailing list should have received a copy of our
earnings press release this morning either by fax or
email. If you did not get the release please call our
Investor Relations office at (803) 217-9466 and we will be
glad to get one to you.
You can also let us know at that time if you want to be
added to our press release distribution list or switch
from fax to electronic delivery of future press releases.
All of our press releases including today's earnings
release are available on our web site at www.scana.com.
A recording of today's conference call will be available
for replay starting approximately two hours after
conclusion of the call. The replay may be accessed through
November 7 either by telephone or on the Internet at
Scana's web site. The dial-in number and conference ID
number for the telephone replay are provided in the press
release.
As a reminder, the reported earnings that we refer to in
our quarterly earnings press release and in this
conference call are prepared in accordance with generally
accepted accounting principles.
In addition to these GAAP numbers we also provide where
applicable another measure of our financial results that
excludes from those GAAP numbers certain gains or charges
as described in our press release.
In compliance with Securities and Exchange Commission
guidelines relating to use of non-GAAP financial measures,
we will continue to provide where appropriate this
additional financial measure which is referred to as GAAP
adjusted net earnings from operations together with the
reconciliation to the GAAP numbers.
We believe this non-GAAP financial measure provides
additional clarity to our earnings analysis, is more
indicative of the company's fundamental earnings power,
and improves comparability of period over period financial
performance.
Finally I'd like to caution everyone that certain
statements that may be made during today's call which are
not statements of historical fact are considered
forward-looking statements and are subject to a number of
risks and uncertainties that could cause actual results to
differ materially from those indicated by such
forward-looking statements, including the risks and
uncertainties discussed in the company's Securities and
Exchange Commission filings. The company does not
recognize an obligation to update any forward-looking
statements.
I will now turn the call over to Kevin.
Kevin Marsh: Thanks John and good morning. I would also like to
welcome each of you to our call. For the third quarter of
2003, Scana reported GAAP earnings of $84 million or 76
cents per share. Those earnings included an additional
after-tax gain of $2 million or 2 cents per share related
to the previously announced sale of (Intercall) by ITC
Holding Company in the second quarter of this year.
Excluding that gain, GAAP adjusted net earnings from
operations in the third quarter were $82 million or 74
cents per share, essentially unchanged compared to
reported earnings in the third quarter of last year of $78
million or 74 cents per share.
Our third quarter results were negatively affected by
abnormally cool summer weather, high natural gas prices
relative to alternative fuels, and industrial
interruptible markets, increases in operating expenses and
share dilution. These factors offset the favorable impact
of higher electric rates, improved results in our retail
natural gas marketing business in Georgia, and lower
interest expense.
We recorded a favorable variance of 5 cents per share in
our third quarter after-tax electric margin. Positive
variances of 14 cents per share from the 5.8% retail
electric rate increase that was effective in February of
this year and 1 cent per share from customer growth were
partially offset by 10 cents per share unfavorable
variance due to milder weather.
As measured by cooling degree days, the weather in our
electric service area during the third quarter was 13%
milder than the warmer than normal weather we experienced
in the third quarter last year.
The milder weather was reflected in a 5.4% decline in
total kilowatt hour sales of electricity. If we had
experienced normal weather during the quarter we estimate
that our after-tax electric sales margin would have been 8
cents per share higher.
Our consolidated after-tax natural gas sales margin was up
3 cents per share compared to the third quarter last year.
That increase was primarily attributable to more favorable
market conditions in our retail natural gas marketing
business in Georgia.
On a consolidated basis, total firm sales of natural gas
were down about 15% compared to the third quarter of last
year. That decrease was driven by a 20% decline in
industrial sales due primarily to intense competition with
lower priced alternative fuels and interruptible markets.
Other factors impacting third quarter earnings were
increases in operating and maintenance expenses of 6 cents
per share, higher depreciation expense of 3 cents per
share, and higher property taxes of 2 cents per share.
Dilution associated with the issuance of 6 million shares
of common stock through a public offering in October of
last year reduced quarterly per share earnings by 3 cents.
We did record a favorable variance of 1 cent per share
from lower interest expense for the quarter due to a
combination of lower interest rates and debt refinancings
and redemptions completed during the past year.
Scana's reported earnings for the first nine months of
2003 were $242 million or $2.18 per share compared to the
reported loss of $184 million or $1.76 per share for the
same period last year.
GAAP adjusted net earnings from operations for the first
nine months of 2003 were $208 million or $1.87 per share
compared to $193 million or $1.84 per share for the same
nine month period in 2002.
Reconciliations of reported earnings to GAAP adjusted net
earnings from operations as well as variance explanations
for the quarter and year to date periods are included in
our press release.
And now some comments on our earnings guidance for 2003
and 2004. The milder than normal weather we experienced in
the first nine months of 2003 reduced our after-tax
electric sales margin by 11 cents per share with 8 cents
of that reduction occurring in the third quarter.
Since our original earning guidance for 2003 was based on
normal weather, we are reducing our 2003 guidance for GAAP
adjusted net earnings from operations from a range of
$2.50 to $2.60 per share to a range of $2.45 to $2.55 per
share to reflect the impact of milder than normal weather
through September.
If the economy and our electric and natural gas service
areas remain soft and if we continue to experience high
natural gas prices relative to alternative fuels and
industrial interruptible markets through the fourth
quarter, the full year earnings could be in the lower half
of that revised range.
Beyond 2003 we are projecting average annual earnings
growth of 4% to 6% compared to our previous earnings
growth target of 6% to 8%. We believe this slightly lower
annual growth rate is more realistic given the slower than
expected recovery we've seen in the national and regional
economy and the prospect of continued high natural gas
prices relative to alternative fuels and industrial
interruptible markets.
On that basis our initial guidance for 2004 earnings is in
a range of $2.55 to $2.75 per share. Our earnings guidance
assumes that we experience normal weather in our electric
and natural gas service areas during the fourth quarter of
2003 and in 2004.
Other factors which may impact our future earnings include
changes in interest rates, the performance of our pension
plan assets, the relative level of wholesale natural gas
prices, and other factors discussed in our Securities and
Exchange Commission filings.
As we have said before, attaining our annual earnings
growth target is not dependent on completing any mergers
or acquisitions nor does it assume the addition of any new
businesses. We believe we can achieve that growth by
continuing to work the strategic plan we have in place
today which is focused on increasing the profitability of
our existing businesses.
Key earnings drivers for us over the next several years
include maintaining historical growth rates in our
electric and natural gas customer base, improving
industrial gas sales and margins at South Carolina
Pipeline, experiencing a sustained economic recovery in
our electric and natural gas service areas, maintaining
consistent earnings in our non-regulated natural gas
marketing business in Georgia, declining capital
expenditures and allow us to become cash flow positive
after completion of the Jasper County Electric Plant in
the spring of 2004, continued paydown of debt from
internal cash flow and with proceeds from monetization of
our remaining telecommunications investments, and recovery
of our remaining expenditures required to complete the
Jasper plant as well as the cost of building the backup
dam at Lake Murray.
Our dividend policy remains unchanged. Our goal is to
increase our annual common stock cash dividend at a rate
that is consistent with the growth in GAAP adjusted net
earnings from operations while maintaining a 50% to 55%
payout ratio. Our current quarterly dividend rate is
34-1/2 cents per share which results in an indicated
annual dividend of $1.38 per share.
As we look to 2004 and beyond, we will remain focused on
fundamentals of operating our businesses efficiently and
profitably for the long term maintaining our position as
an industry leader in customer satisfaction and providing
increasing value for our shareholders.
Now I'd like to review third quarter results for our major
businesses. First I will review results in our regulated
businesses. As we have noted before, these operations
represent more than 90% of Scana's total assets and has
consistently contributed more than 90% of our GAAP
adjusted net earnings from operations.
Reported earnings in the third quarter in South Carolina
Electric and Gas Company, our principal subsidiary, were
$88 million or 80 cents per share compared to $86 million
or 82 cents per share in the same quarter in 2002.
As with Scana, the major factors impacting third quarter
earnings at SCE&G were milder weather, increases in
operating expenses, and share dilution. Those factors
offset the favorable impact of higher electric rates and
solid growth in our electric customer base.
As I mentioned earlier, total kilowatt hour sales of
electricity were down 5.4% in the third quarter of this
year compared to the same quarter last year. That decline
reflected the milder summer weather and a soft economy.
Residential sales which is the most weather sensitive were
down nearly 9%, commercial sales were down about 5-1/2%,
industrial sales rose about 2%, wholesaler all systems
sales were down 12% reflecting the milder weather and the
sluggish economy.
At September 30, 2003 SCE&G were serving approximately
567,000 electric customers and about 270,000 natural gas
customers. Over the past year SCE&G's electric customer
base has increased about 2% while the number of natural
gas customers increased about 1-1/2%.
SCE&G's summer nuclear station was shut down on October 10
for a normal refueling and maintenance outage. This outage
is scheduled to last about 36 days and is currently on
schedule.
On October 20 a routine inspection revealed a small amount
of dry boron powder on a non-corrosive, stainless steel
injection line pipe attached to one of the plant's three
reactor coolant pumps. Boron is added to the coolant to
help regulate the core and control the nuclear reaction
and is also used in leak detection.
Follow up examinations revealed two surface crack
indications at a weld attaching a 1-1/2 inch pipe to the
pump. We reported this problem to the NRC that same day.
There was no impact to safety or plant operations from
this leak.
Subsequent inspections of the other two reactor coolant
pumps have been completed and no problems were found.
Plant personnel have decided to replace a small section of
the pipe and put in a new weld. The work should take about
a day to complete and will be this weekend.
Similar repairs of this type which are minor in nature
have been performed twice at the plant in the past. This
action will not alter the outage timeline nor will it
materially impact the total cost of the outage.
The approval process as it relates to the company's August
2002 application to the NRC for a 20 year license
extension for summer station is now more than halfway
complete. In a draft environmental impact statement issued
in July, the NRC found that there are no adverse
environmental reasons that would prevent the plant from
operating over the extended period of time.
Public hearings on the license extension were held at the
plant in August with no major issues. We expect a final
decision from the NRC on our application around the middle
of next year. Renewal of the plant's license would extend
its operating life from 2022 to 2042.
South Carolina was very fortunate not to have received any
significant damage from Hurricane Isabel which came ashore
in North Carolina's outer banks in mid-September and moved
northward.
Tragically, this tremendous storm resulted in a number of
deaths and injuries and caused extensive damage to both
personal and business property including electric
transmission and distribution systems up the East Coast.
In response to the widespread power outages, SCE&G sent
two storm teams totaling more than 140 personnel to assist
with power restoration in parts of North Carolina and
Virginia. These crews worked for nearly two weeks under
extremely adverse conditions to repair and rebuild
portions of the electric systems destroyed by the
hurricane.
We at Scana greatly remember the timely assistance we
received of utilities after Hurricane Hugo caused
significant damage to our electric distribution system in
1989 so we were pleased to be able to lend a helping hand
to restore electricity and some semblance of normalcy in
areas devastated by this terrible storm.
PSNC Energy, our North Carolina retail natural gas
distribution company, reported a seasonal loss of $7
million or 6 cents per share in the third quarter of 2003,
relatively unchanged compared to the third quarter of
2002. Improved sales margins driven primarily by customer
growth were offset by higher operating expenses.
Since 1996 PSNC Energy has been working to extend natural
gas service to areas of western North Carolina. This
expansion has been made possible through the North
Carolina Natural Gas Expansion Act which was enacted in
1991 and provides funds to extend natural gas service into
areas of the state that would otherwise be uneconomical to
serve.
In July 2003 PSNC Energy began the final phase of its
western North Carolina expansion which includes the
addition of 22 miles of transmission pipeline and 23 miles
of distribution pipeline that will stretch into the cities
of Dillsboro, Cherokee, and Bryson City which are located
in the mountainous areas of western North Carolina.
A unique element of this project includes running service
to the Cherokee Indian Reservation. Construction has been
completed up to the Cherokee City gate. The remaining
installation of 6 miles of 6-inch transmission pipeline
will finish the project at Bryson City. The overall
project remains on schedule and construction should be
completed by April of 2004.
South Carolina Pipeline Company, our intrastate natural
gas transmission subsidiary, reported break even results
in the third quarter of 2003 compared to earnings of $4
million or 3 cents per share in the same quarter last
year. Two factors continue to have a constraining effect
on pipeline's results.
First and most importantly, sales margins on competitive
sales of natural gas to our industrial interruptible
customers have been reduced as a result of higher natural
gas commodity prices.
As we have said before, the wholesale prices of natural
gas rise relative to competing fuels, Pipeline must
produce its margins in order to retain industrial
customers who have the ability to burn lower priced
alternative fuels --principally the number two fuel oil.
In addition, the demand for natural gas as a fuel for
electric generation has declined as a result of milder
spring and summer weather across the Southeast region. As
I mentioned earlier, improving Pipeline's future
profitability is an important part of our earnings growth
strategy.
From an operating perspective we are continuing our
efforts to expand the available supply of natural gas in
our existing markets. SCG Pipeline, our newest subsidiary,
has completed construction of an 18-mile intrastate
transmission pipeline that will bring additional supplies
of regassified, liquified natural gas from a facility of
Elba Island, Georgia in Jasper County, South Carolina.
This $32 million project which was completed during the
third quarter on schedule and on budget will provide a new
source of natural gas for our existing markets in South
Carolina and Georgia and will also supply SCE&G's new 875
megawatt natural gas powered electric generating facility
which is currently under construction in Jasper County.
In August South Carolina Pipeline began construction on a
38-mile natural gas transmission pipeline that will link
the new SCG pipeline in Jasper County with South Carolina
Pipeline's existing intrastate transmission system in
Hampton County, South Carolina.
Over 90% of the route for this extension which is called
the South System Loop will parallel an existing electric
transmission corridor, lowering construction costs and
minimizing the impact to the environment.
Connecting these two pipelines will allow us to continue
to deliver natural gas to our existing customers in a
reliable, cost effective manner while providing for future
growth. The South System Loop project is expected to be
completed in the spring of 2004 at an estimated cost of
approximately $25 million.
Turning to our non-regulated businesses, Scana Energy, our
retail natural gas marketing business in Georgia, reported
break even results in the third quarter of 2003 compared
to a loss of $4 million or 3 cents per share in the same
quarter last year.
That improvement primarily reflects higher sales margins
resulting from customer growth and more favorable market
conditions which more than offset higher operating and
customer service expenses.
Scana Energy continues to maintain its position as the
second largest natural gas marketer in Georgia with about
a 25% market share. As of September 30 the company was
serving more than 350,000 non-regulated retail customers
and an additional 31,000 customers through its regulated
division.
Our other non-regulated businesses which include Scana
Communications, Service Care, Prime South, and the
non-Georgia component of Scana Energy Marketing and the
holding company have combined reported earnings in the
third quarter of 2003 of $2 million for 2 cents per share.
Those results include the additional gain of $2 million or
2 cents per share related to the customary host closing
working capital true-up following the sale of our ITC
holding company investment in the second quarter of this
year.
By comparison, these non-regulated business reported a
combined loss of $2 million or 2 cents per share in the
third quarter of 2002. Lower interest expense was a major
factor contributing to the favorable quarterly variance.
And now I'd like to review the status of the two major
capital projects we currently have underway at Scana. Work
on SCE&G's new Jasper County Electric Generating Plant
continues on schedule and on budget.
This $450 million plant will utilize three natural gas
fired, combustion, turbine generators and one steam
turbine generator to generate up to 875 megawatts of
electricity that will help us meet the growing energy
needs of our customers for many years to come.
The facility is being constructed under a fixed price,
turnkey contract and is expected to be completed on budget
and on schedule in the spring of 2004. Approximately 60%
of the estimated $450 million cost of the Jasper plant is
currently included in our electric rates.
As we have said before, we will finalize our strategy for
recovery of the remaining capital costs associated with
the Jasper plant after it is completed next year.
Construction of the backup dam at Lake Murray near
Columbia is now about 1/3 complete and the $275 million
project remains on budget and on schedule for completion
in 2005. This 50,000 acre lake is part of a federally
licensed hydroelectric project that is under the
jurisdiction of the Federal Energy Regulatory Commission.
FERC is requiring SCE&G to construct the backup dam to
comply with more stringent earthquake safety criteria. The
second dam would assure the stability and integrity of the
lake during or after a hypothetical, worst case
earthquake.
We are continuing our evaluation of potential alternatives
and scenarios that will allow for recovery of the
estimated $275 million in capital costs associated with
the construction of the backup dam. A final decision on
this matter will not be made until the project is closer
to completion.
And now a few comments on our synthetic fuel operations.
For those on today's call who may be new to our story, I
would like to provide a brief summary of our syn fuel
business.
South Carolina Electric & Gas Company culled Equity
Investments and two partnerships involved in producing
synthetic fuel. These syn fuel production facilities which
are located at the Wateree and Canada generating stations
were placed in operation in 2000 and 2001 respectively.
The partnership that operates with Wateree syn fuel
facility received a private letter ruling from the IRS in
December of 2001 which we can rely on as a partner. A PLR
has not been requested for the sun fuel production
facility at the Canada station which uses virtually the
same production process as the Wateree facility.
Through September 30 of 2003, these syn fuel production
facilities have generated a combined total of
approximately $59 million in net syn fuel tax credits for
SCE&G. And like most utilities, SCE&G has not been
recognizing the value of the syn fuel tax credits in its
income statement.
Under an accounting plan requested by the company and
approved by the South Carolina Public Service Commission
in 2000, the company is deferring the current income
statement benefit of the syn fuel tax credits net of the
applicable partnership operating losses and recording that
benefit on the balance sheet as a deferred credit.
SCE&G does receive a cash flow benefit from a reduction in
current federal income taxes. The syn fuel credits that
are currently being deferred are expected to be applied in
the future for the benefit of our customers.
The IRS review of the syn fuel industry has recently
focused on the scientific validity of test procedures and
results that have been presented as evidence that solid
coal based synthetic fuels have undergone a significant
chemical change as a result of the syn fuel process.
As was widely reported earlier this week, Progress Energy
announced it has been advised by the Internal Revenue
Service that the Internal Revenue Service had concluded
its inquiry of chemical change at one of that company's
synthetic fuel facilities. Although this news has no
direct impact on SCE&G, we do believe it is a positive
development for the industry.
The chemical change agents used in the syn fuel production
process at SCE&G's plant is a complex, hydrocarbon
emulsion that differs from those used in some other syn
fuel processes. We systematically collect samples of our
syn fuel production that are subjected to regular testing
by both internal and independent experts.
Based on the results of those tests, we are confident that
we have operated these facilities in a way that is in
compliance with the procedures outlined in the private
letter ruling submission.
Primesouth, one of our non-regulated subsidiaries, also
operates a syn fuel production facility for a third party
and receives management fees, royalties, and expense
reimbursements related to those services that contribute
about $7 million to that company's annual net income.
Primesouth does not receive any tax credits associated
with the production of syn fuel at this facility. To date
there has been no negative impact to Primesouth syn fuel
operations as a result of the Internal Revenue Service
review.
And now a brief update on our telecommunications
investments. Our investment portfolio remains unchanged
with investments in (Knowledgy), (ITC Delta Com), and
Magnolia Holding Company representing a total cost basis
of approximately $154 million.
As we have said before, our plan is to monetize our
remaining telecom investments in a prudent and timely
manner and continue to use the cash proceeds to pay down
debt at the holding company.
And finally some comments related to the issuance of stock
options by Scana. During the period 2000 to 2002, our
Board of Directors granted non-qualified stock options to
certain key employees under the company's long-term equity
compensation plan. The total number of options granted was
approximately 2 million shares or less than 2% of the
total shares currently outstanding.
To date, approximately 284,000 new shares of Scana common
stock have been issued under this plan. About 664,000
options are currently exercisable and an additional 1
million shares will be exercisable in the future.
The Board ceased issuing options in 2002. Since there are
no longer options being issued under this plan and to
limit any dilution related to these options, the company
is purchasing outstanding shares of its common stock on
the open market as the options are exercised. The number
of shares repurchased will be limited to the total number
of options exercised.
To date approximately 264,000 shares of common stock have
been repurchased at a net cost to the company of
approximately $1.4 million.
That concludes my prepared remarks and I will now be happy
to respond to your questions.
Operator: Ladies and gentlemen, I would like to remind you in order
to ask a question, please press the Star then the number 1
on your telephone keypad. We'll pause for just a moment to
compile the Q&A roster.
Your first question comes from the line of (Tim Winter)
with AG Edwards.
Kevin Marsh: Hello (Tim).
(Tim Winter): Hello Kevin, good morning. Could you talk a little bit
about what some of your options will be for rate relief
at Lake Murray and what your plans are for Jasper?
Kevin Marsh: Let me address Jasper first. That plant we expect
to be completed around May of next year. I believe the
deadline - schedule date is May 1. At that time we'll
assess the amount and timing of any rate relief that may
be necessary to recover from that remaining investment so
we wouldn't have a final decision on that until sometime
probably near the middle of next year.
I think with respect to the dam work that's being done,
that's not going to be completed until near the end of
2005. So we've got a considerable amount of time between
now and then to wait and see.
The impact of any rate relief that might be in effect for
the remaining Jasper plant as well as just where we stand
on earnings as a result of turnaround in the economy, the
fact that we should be cash flow positive at that point
should have allowed us to pay down some additional debt,
improve the earnings situation.
So we're really not close enough to any final decision on
the dam. We do have the syn fuel tax credits that we
talked about on our last call that continue to be deferred
on the books at SCE&G that could be considered in the
evaluation of offsetting some of the costs of the dam if
that's the direction the Commission wanted to go.
(Tim Winter): Okay, and can you talk a little bit about AFUDC
expectations for '03 and then '04 once the plant is
complete?
Kevin Marsh: I believe we estimate about $43 million on an annual in
AFUDC for this year. Let me get somebody to check that
number while we're talking. That certainly will go
down when that plant goes into service in May. We'll have
to cease AFC on that.
Yeah, I think on the AFC, yeah $43 million for 2003. I
don't have the exact number on that. I could get you to
follow up with John Winn and we could give you the AFC
balance of the - construction balance at that time the
plant would go down.
(Tim Winter): Okay great, thank you.
Operator: Your next question comes from the line of (Tom Hanlen)
with Wachovia Securities.
(Tom Hanlen): Good morning Kevin.
Kevin Marsh: Good morning.
(Tom Hanlen): About the two plants with the tax credits, one with
the PLR and one without. Can you break down the $59
million of credits between the two plants?
Kevin Marsh: I don't have a breakdown here in front of me. I'll
be glad to follow up with you on that question. I think
the important thing to note about those two plants is they
use the same technology and the same process. They're
pretty much the same vintage plant so there's not really
any significant differences in their operations.
(Tom Hanlen): Have you applied for PLR for the second one?
Kevin Marsh: We have not.
(Tom Hanlen): Okay, thanks a lot.
Kevin Marsh: Okay.
Operator: Your next question comes from the line of (Jay Henelo)
with UBS.
Kevin Marsh: Hey (Jay).
(Jay Henelo): Hi, good morning. I realize you mentioned the
impact of high gas prices kind of at the industrial level
and what that might have on your guidance and growth rate
going forward. Have you reflected on the impact that might
have on elasticity of demand at the retail level -- what
impact that might have, it might not have?
And also while we're on the subject of gas, can you give
us a little update on what's going on with Scana Energy,
what type of contracting is going on and what the overall
environment is there. Thank you.
Kevin Marsh: Okay. The question related to the impact of elasticity
really just for other demand on the gas side of the
business is something we are studying at this very point,
trying to understand what impact that may have on our
long term margins.
I think the combination of the economy downturn with the
high gas prices has made it somewhat difficult to make an
exact distinction between the two. We do know from
research we've already done that as newer homes come on
service or come online with more efficient appliances,
that does put some downward pressure on the actual gas
that's burned in homes of the same size.
But that's been offset at this point - more than offset by
the additional growth we've seen on the system.
I think in areas of North Carolina for example where we
certainly have more cold weather there than we do in South
Carolina and in Georgia, we've been able to outstrip that
decline by increases in customers on the system.
It is something we will continue to watch. I think we'll
also need to watch the impact of that just relative to the
electric alternatives that customers have. But at this
point we've not seen any significant change from the
patterns we've seen in previous years.
We've not had a sustained period of three or four years of
high gas prices. Certainly we're all anxious to see what
happens this fall and this winter and what that does to
gas prices over the long term and we'll stay close to
that.
(Jay Henelo): Okay, the reason I brought it up is that I
appreciate you're going to stay close to it. That is
great. NFG announced this morning that they are lowering
guidance because of that and I just thought that was
noteworthy and that was the catalyst for asking.
Kevin Marsh: Yeah, we don't see any impacts on our guidance
related to the gas business at the retail level for your
residential and commercial customers. Our concerns really
come on the industrial interruptible sales where we have
to compete against alternative fuels where we've seen
pressure at South Carolina Pipeline this year.
(Jay Henelo): Okay.
Kevin Marsh: I think your final question was on the contracts we have
in Georgia, I think you were referring to those. The
majority of our customers are still on variable
contracts. I think it's about 10% are on fixed and the
rest are on variable.
(Jay Henelo): Okay. And any dynamics about competition, lack thereof or
just any other flavor down there you could provide?
Kevin Marsh: You know, the market compared to prior years seems to
be fairly settled. The competitors seem to be acting
rationally. I think gas prices are high which has put
pressure on everybody to watch margins very carefully.
The customer service aspects of the business which were
some of the biggest problems we had in early years seem to
have leveled out. I know we are very satisfied with the
customer service operation we have in service.
But we will continue to be aggressive in that market and
make sure we can maintain our market share.
(Jay Henelo): All right, thank you.
Kevin Marsh: Okay.
Operator: Your next question comes from the line of (Paul Patterson)
with (Glenrock) Associates.
Kevin Marsh: Hey (Paul).
(Paul Patterson): Hi, how are you doing?
Kevin Marsh: Good.
(Paul Patterson): Just - I was wondering if you could just go over for us
the allowed - the earned ROE at the utilities the last
12 months.
Kevin Marsh: Yeah, the allowed is of course at SCE&G is 12.45%
which is what we got in the last case. You know, so far
we're probably running slightly below that, probably
around 11% for the first part of this year. And at PSNC in
North Carolina they're allowed I believe it's 11.4% and
we're right at 11% in those operations.
(Paul Patterson): Okay great. Then I also wanted to ask you in
terms of the pipeline, I mean, you always mention that the
reason why you're lowering your growth target to 4% to 6%
is because of the economy and the pipeline. And I can see
how the pipeline did worse in the third quarter, but year
to date it looks like it's done better by 4 cents - or by
3 cents I guess versus the year, looking at the variance.
What are your expectations I guess going forward? I mean,
what are the dynamics that, I mean, is there something in
the last quarter that's, I mean, because we've had high
gas prices, you know, I mean.
I'm just trying to get an idea as to what's going on there
at the pipeline that - other than obviously you mentioned
the switching and stuff. But it looks like you guys had
better year over year at least the nine months. So could
you clarify that for me?
Kevin Marsh: Yeah, I think if you go back to '01, '01 was
especially tough because we had some fixed price gas. We
were working through the system and that really hurt us on
a competitive basis. That was early in 2002. That was what
I meant, 2002. So you're really comparing into a year that
was down.
We have seen the pressure this year. Prices have been up
above $5. When they get at the $5 level or below that,
that certainly improves our ability to compete.
If you go back and look at pipeline on an annual basis,
they've generally contributed between 10 to 15 cents a
share which is a pretty normal range for them. We've seen
pressure on that last year. We've seen pressure that will
likely bring us in below those numbers for this year.
So we're not talking about a huge increase in dollars they
need to turn around to pipeline. But even, you know, 4
cents a share for us has a big impact on the overall
growth rates.
So we need to see them return to more normal levels to
again push us, you know, from the 4 to 6 we're talking
about now, you know, up to the high end and possibly
higher on that range.
(Paul Patterson): With respect to that though, when you say the 4% to 6%
growth, is that a longer term growth rate or is that
just for 2004?
Kevin Marsh: We're going to give that I think on an annual
basis. I mean, certainly I think what we expect to see
annually and long term I would tell you are both 4 to 6
right now based on what we can see and as far out as we
think the picture is clear with the economy.
I know we had talked about 6% to 8% being the longer term
view over a three to five year period and not necessarily
in one particular year. I think with this 4% to 6%
guidance we've got out there for you now, you can expect
that each year.
(Paul Patterson): Okay, and then in terms of weather year to
date versus normal, I mean, I know that's 8 cents I think
it is for the - or is it 3 cents - it's, yeah, just year
to date what was versus normal? What are we looking at in
terms of weather?
Kevin Marsh: Versus normal on a year to date basis, 11 cents per share.
(Paul Patterson): It's negative?
Kevin Marsh: Yes, negative.
(Paul Patterson): So okay, so okay, that's going to benefit theoretically if
you have normal weather next year, right?
Kevin Marsh: Yes.
(Paul Patterson): Okay so - and then finally in terms of Georgia Gas, you
guys mentioned improved sales margin and customer
growth. Could you just elaborate a little bit more?
I mean, what's causing sales margin growth? What's
actually happened there? Is it just - have you guys gotten
a lot of new customers? I mean, you guys mentioned that
there are also some expenses that have increased.
What are the dynamics that allowed you to do so well there
this quarter?
Kevin Marsh: Well I think the biggest piece of that is we
understand the market better every year. The market has
been less volatile than it has been in prior years in
terms of customers coming and leaving the system as well
as gas prices.
Although gas prices have been up, we have done I think a
good job improving our ability to purchase gas and manage
our storage and blend that with our hedging activities
where necessary to keep us competitive and improve the
margins.
It would be difficult to point to just one thing.
Certainly margins is a real driver in the market over
there. So our ability to price the gas competitively and
just improve the cost of gas, we can bring the marketplace
to our back office operations has had the biggest impact.
(Paul Patterson): Okay, thanks a lot. I appreciate it.
Kevin Marsh: Okay.
Operator: Once again ladies and gentlemen, I would like to remind
you in order to ask a question, please press Star then the
number 1 on your telephone keypad. We'll pause for just a
moment to compile the Q&A roster.
Your first question is a follow-up question from the line
of (Tim Winter) with AG Edwards.
Kevin Marsh: Hello again (Tim).
(Tim Winter): Hello Kevin. Can you talk about what's going into your
expectations as far as pension goes? Are you looking
for an improvement there?
Kevin Marsh: We do expect to see an improvement in the pension
income next year. I think last year we had pension income
somewhere around $20 million, $22 million in total for
Scana. That number is done probably to around $6 million
or $7 million this year.
That was based on a pension asset base of around $670
million which is now up probably around $730 million, $740
million. So we've seen improvement in the asset base
that's in the pension plan. And as you know, that's the
real driver for us on pension income.
The difficult part in predicting that is under the
accounting rules that determine the actual income you'll
recognize. You take a snapshot of that market value at the
end of the year.
So certainly as those assets continue to improve, the
asset market values continue to improve that will improve
the likelihood of an increase in pension income for next
year which we do anticipate.
(Tim Winter): Okay, thank you.
Kevin Marsh: Okay.
Operator: Your next question comes from the line of (Neil Stein)
with (John Levin) & Company.
(Neil Stein): Hi. When you were in New York last time, you mentioned
there might be some change in the way Commissioners -
the South Carolina Public Service Commissioner appoints
it. I don't remember the exact details but do you have
an update on that issue?
Kevin Marsh: Nothing has really changed. The legislature continued
to debate that issue as time expired earlier this year.
I suspect that will be one of the first items up on the
agenda next year. So you really won't have a decision
in 2003 on that.
That would come - I think the state House takes office up
there around - end of January, early February next year.
And I expect it to be one of the first items they bring up
for debate.
(Neil Stein): Could you just sort of take a step back and remind me
exactly what the issue was?
Kevin Marsh: Our Commissioners here in South Carolina go through
a qualification process where they're reviewed by a merit
panel and then put up to the legislature for a vote. They
have been debating the qualifications of people that can
go through that process. They are trying to decide what
the educational requirements are and some issues related
to nepotism and things of that nature.
So I think it will have some impact on us. It would be
difficult to predict how it might impact the Commissioners
that are sitting today. But mot of those issues have to do
with the qualification of the candidates and not the
process whereby they are selected.
You know, right now they come in, they're in two year
terms, and then they're talking about possibly changing
some of the terms, staggering some of the terms, so issues
of that nature more than the actual way they're selected.
(Neil Stein): Right now I think all their terms have kind of
expired but they're kind of just going to stay on the
Commission until this issue gets resolved?
Kevin Marsh: Yes, the current Commission will remain in place.
(Neil Stein): Okay, very good. Thank you.
Kevin Marsh: Thank you.
Operator: Your next question comes from the line of (Douglas Lee)
with UBS.
(Douglas Lee): Hi, good morning guys. I have two questions related to
the syn fuel business. The first is about $59 million
in net syn fuel tax credits. Is that a since inception
number or is that year to date '03?
Kevin Marsh: That's a since inception number.
(Douglas Lee): Okay. My second question related to syn fuels is my
understanding is that there are three primary processes
that you can use to process the syn fuel -- (earth coal),
(start tech), or (Coval). Which methodology do you
use for your facilities?
Kevin Marsh: Well the facilities we have were designed and built
by (Coval) technologies. The process we use is one that
uses a complex hydrocarbon emulsion which is manufactured
by the Heritage Research Group referred to as the Heritage
Technology which is what we employ at the plants.
(Douglas Lee): Okay, thanks guys.
Kevin Marsh: Okay.
Operator: Your next question is a follow-up question from the line
of (Paul Patterson) with (Glenrock) Associates.
Kevin Marsh: Hey (Paul).
(Paul Patterson): Hey. Just a little bit more of a picture on
the economy down there, you know, what is it that's
primarily causing the drag down there? You know, any
insight there that you could just share with us and why
you guys think it isn't going to improve in 2004, what
have you? Or whether you guys are just being cautious
about it?
Kevin Marsh: Well we're being cautious. But I will tell you if you
go back and look at the past three or four years, we
have not come close really towards the end of '02 and
especially in '03 bringing in a new business to the
state, we saw it in three to four years prior to that.
We had a couple of record-setting years where I think we
actually brought in more than North Carolina and Georgia
if you compared us to each of those two states which was
really I think a good sign for us.
And you had all of course the ancillary benefits that go
along with that with new people coming to the state that
are just healthier people economically in the state able
to do other things and run related businesses.
We continue to see growth, it's just not as robust as it
has been in prior years. And we think it's more prudent
for us to be conservative in the estimates based on what
we see until we see some clear indications of, you know,
consistent turnarounds.
We have seen I guess on the industrial side we have
continued to see some shutdowns in textile industries. All
of that has not occurred this year. That's a process that
has actually occurred over two or three years. But that
continues to be a drag. And I don't know that those
businesses will ever come back as strong as they have been
in the past.
(Paul Patterson): Okay, what is the retail sales growth that you guys are
predicting? I mean projecting going forward from the
utility business?
Kevin Marsh: Our growth is usually in that 2%, 2-1/2% range.
(Paul Patterson): Okay. And what did you guys have before?
Kevin Marsh: It's pretty much 2%, 2-1/2% on the retail side.
(Paul Patterson): Okay, great. Thanks a lot.
Kevin Marsh: Okay.
Operator: At this time there are no further questions. Do you have
any closing remarks?
Kevin Marsh: I want to thank everybody for participating in the call
today. I know there was a lot of information we went
through. If you have any follow-up questions or any
additional information, please contact John Winn in
Investor Relations.
Thanks and have a great day.
Operator: Thank you for participating in today's conference. You
may now disconnect.
END