Southwestern Energy Company Conference Call Summary
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2000 Third Quarter Results Conference Call
Tuesday, October 31, 2000
Chaired by
Harold Korell
President and Chief Executive Officer
Korell: Good morning and thank you for joining us today. With me are Al
Stevens, the President of our E&P segment; and Greg Kerley, our Chief Financial
Officer. After some preliminary comments, I'll turn the floor over to Al for an
update on our E&P operations and then to Greg for comments on our financial
results. After that, all of us will be available for questions. If you've not
received a copy of the press release announcing our third quarter results, you
can call Carole Ann at 281-618-4710 and she'll fax a copy to you.
Also, our attorneys have asked that I point out that some of the
comments during this teleconference may be regarded as forward-looking
statements that involve risks and uncertainties which are detailed in the
Company's Securities and Exchange Commission filings. While we believe they are
reasonable representations of the company's expected performance, actual results
could differ materially.
Our financial results for the third quarter continue to show
improvement from prior years with our operating income for the quarter
increasing to $5.9 million, more than triple last year's level of $1.7 million.
We expect significant improvements in the fourth quarter as well, as our hedge
position becomes more favorable.
The results from our E&P operations continue to be very encouraging.
Reserve additions for 49.2 Bcfe through the first nine months replacing 185% of
our year-to-date production. Also, our production volumes for the third quarter
were up nicely by 13% over last year and by 8% for the year-to-date. We're
continuing to pursue the sale of our utility operations and are hopeful that we
will have something to announce on that in the fourth quarter. So we'll keep you
informed on this front, but we don't have any other comments at this time.
We also recently received the judge's ruling in the first phase of the
EOG lawsuit. If you remember, the case was broken into two parts: the liability
phase which has been completed, and a damages phase. The case went to a non-jury
trial as to liability in January of 2000. EOG was originally included in, but
opted out of, the Hales class action litigation. Their claims included fraud and
Hales-like damages. The court ruled that the Company did not commit fraud and
that the statute of limitations cuts off any overriding losses due prior to
March 1, 1990. The court is scheduled to hear testimony on the damages phase of
the trial in January of 2001, so it's not appropriate for me to speculate what
the number might be except to say that the court did not
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adopt the Hales case for calculating Contract 59 damages. Overall, we view the
court's findings as positive.
We're moving forward with our balanced investment strategy in our E&P
operations, and that's working, and we remain focused on the fundamentals to
create value for our Company and our shareholders. That concludes my comments
and I'll now turn the teleconference over to Al Stevens for an update of the E&P
operations.
Stevens: Thank you, Harold. In the first quarter of 2000 we continued to
increase our production rates and activity levels due to our
internally-generated exploration and exploitation program. Production was 9.0
Bcfe for the third quarter, up from 8.9 Bcfe in the second quarter and 8.0 Bcfe
for the same period in 1999. In total, Southwestern Energy participated in 24
wells that were spud in the third quarter. Of these, 15 were successful, five
were dry and four are still in progress. So far in 2000, we have participated in
92 wells as compared to 82 wells in all of 1999.
We continue to be active with our Arkoma Basin drilling program. In the
third quarter we spudded 11 wells, of which eight were productive. Two wells of
note are the Louis Ambrose No. 1-17 and the Briggs No. 2-12. The Louis Ambrose
well is located in the Cherokee prospect of LeFlore County, Oklahoma, in which
we hold a 50% working interest. The well tested 4.8 million cubic feet per day
from the Basham sand at 4,900 feet and it's currently shut-in awaiting pipeline
connection.
Southwestern holds a 35% working interest in the Briggs well located in
our Haileyville prospect in Pittsburgh County, Oklahoma. This well tested at a
rate of 6.4 million cubic feet per day from the Dirty Creek formation at
approximately 8,250 feet and is also awaiting a pipeline. In addition to our
activity in the Arkoma Basin, the continuing development of our Bimini discovery
in the Permian Basin has yielded excellent producing rates. The Bimini Nos. 1, 2
and 3 wells, located in Lea County, New Mexico, are currently producing at a
combined gross rate of 740 barrels of oil per day and 650 Mcf per day. We are
currently completing the Bimini No. 4 well and expect to start the Bimini No. 5
in mid-to-late November, just depending on rig availability. Southwestern
working interest in these wells ranges between 55% to 100%.
Our total Permian Basin activity in the third quarter included
participation in 12 wells, of which eight were productive and three were dry
with one still in progress. The last time we met, I discussed the status of our
three internally-generated south Louisiana prospects -- Havilah, Brigadoon, and
Malone. Since that time, we have reached total depths of 16,850 feet on our
Havilah prospect in October. We are currently preparing to test the Nodasaria
formation at approximately 14,950 feet and expect to have results in the near
future. Southwestern operates this well in Lafayette Parish with 27.5% working
interest.
On Brigadoon in St. Martin Parish, we reached a total depth of 18,225
feet. The objective sands were present, but they came in structurally lower than
anticipated, and the well was plugged. Southwestern held a 20% capital interest
in the Brigadoon prospect.
Finally, on Malone we are currently drilling at approximately 14,100
feet on our way to a total depth of 17,000 feet. In the intermediate hole, mud
logs and resistivity logs indicate 40 feet
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of pay in the Marg A sand at 12,400 feet. The Marg A is the first of six
objectives in the Malone prospect. Southwestern also operates this well in
Assumption Parish with a 33% working interest.
Production from our North Grosbec discovery made earlier this year is
holding up very nicely. The well is currently producing at 15 million cubic feet
per day and 575 barrels of oil per day with a flowing tubing pressure of 8,800
PSI. Southwestern owns a 25% working interest in the well, and we anticipate
spudding the second well on this structure in December.
As I'm sure you're aware, the availability of drilling rigs has been
significantly reduced, particularly in east Texas due to increased activity in
the industry. For the last several months, we have been attempting to locate
rigs to initiate our in-fill drilling program in the recent Overton field
acquisition. I'm pleased to tell you that it looks like we have lined up two
rigs to start the drilling program late this year, and we anticipate drilling
10+ wells in the next year's program.
I continue to be very pleased with our performance in 2000. We are
continuing to develop internally-generated prospects, and we already have an
inventory of projects extending beyond our expected activity level for 2001. We
expect activity in the industry to remain high well into next year, and we have
already begun detailed logistical planning for our 2001 drilling program. I
would like now to turn it over to Greg Kerley who will discuss the financial
results.
Kerley: Thanks, Al and good morning. As Harold indicated, our financial results
in the third quarter continue to show improvement from prior years. In the third
quarter of 2000, we reported a loss of $754,000, or $.03 per share compared to a
loss of $1.9 million, or $.08 per share during the same period last year. The
third quarter 2000 results included an unusual charge of $2.0 million related to
litigation against the Company. Excluding the unusual charge, the Company would
have reported net income of $466,000, or $.02 per share for the quarter.
Operating income in the third quarter increased to $5.9 million, more
than triple last year's level of $1.7 million. Cash flow from operating
activities, before working capital changes and the unusual charge, was $13.2
million during the quarter, up from $12.3 million for the third quarter of 1999.
Improved operating results from the Company's E&P segment more than offset the
normal seasonal loss experienced by our utility segment. Operating income for
our E&P segment was $7.2 million in the quarter, almost tripling the segment's
operating income from last year's level. The improvement was due to a 13%
increase in production volume and to higher oil and gas prices.
Our financial results would have been even stronger except that we had
commodity price hedges that were put in place in 1999 on 5.6 Bcf of our third
quarter gas production at $2.38 per Mcf. Including the effect of our hedged
volumes, we realized an average price of $2.87 per Mcf for our gas production in
the quarter, up from $1.99 per Mcf last year. Our oil price also improved during
the quarter, averaging $21.56 a barrel compared to $19.21 per barrel last year.
We expect significant improvement in our average realized gas price
during the fourth quarter as our hedge position becomes more favorable. The
company's complete hedge position is disclosed in our Form 10-Q filings which
are also available on our web site. Production and
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operating expenses for the E&P segment increased to $3.6 million during the
third quarter of 2000 compared to $2.7 million for the same period in 1999. The
increase was due to higher production and an increased number of workovers
performed during the quarter. Lifting costs on an equivalent unit of production
basis were $.40 per Mcfe in the third quarter of 2000 compared to $.34 per Mcfe
in the third quarter last year. Our lifting costs are still some of the lowest
in the industry.
Depreciation, depletion and amortization expense for the E&P segment
was $10.1 million for the quarter, up from $8.3 million for the same period of
1999. The increase was due to higher production volumes and a higher
amortization rate. The amortization rate for the full cost pool in the third
quarter was $1.09 per Mcfe as compared to the prior year rate of $1.01. The
level of the unamortized portion of our full cost pool has steadily declined
over the last few years and is currently $33.8 million.
Operating income for our gas distribution segment was a seasonal loss
of $1.7 million in the quarter compared to a loss of $1.5 million for the same
period in 1999. The decrease in operating income is primarily the result of
lower rates that were implemented in December of 1999.
Our interest expense is up $2.3 million in the third quarter compared
to the same period last year due to our increased debt level related to funding
the Hales judgment. We are focused on improving our capital structure as quickly
as possible through the proposed sale of our utility and are working hard to
achieve this.
Our capital expenditures totaled $57 million during the first nine
months of 2000 and $53 million of that has been invested in our E&P operations.
During the third quarter we also received $12.3 million of proceeds from the
previously announced sale of some of our non-strategic Oklahoma properties. That
concludes my comments, so now we'll turn back to the operator who will explain
the procedure for asking questions.
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Questions and Answers
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1. In terms of non-core divestiture packages, do you feel like you're pretty
much finished now and going forward you'll look to only grow the E&P asset base.
Kerley: Yes, the properties that were sold in Oklahoma were the lower tier of
some non-core, non-operated properties. We may have some minor sales of marginal
properties going forward, but it should be very minor compared to that.
2. What is your expected capital spending for next year, not only overall but
broken out between the E&P and the gas distribution side.
Korell: Fundamentally, we're thinking at this time of capital spending in E&P
sort of on the low end of $75 million, and another $6 million probably for the
utility as we review it right now. We have the potential to add upward to that,
depending upon outcomes of the utility sale and so on. So, all that would have
to be adjusted in there.
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3. You'd mentioned that you're hoping to have some sort of an update in the
fourth quarter on the sale of the utility. Any sort of updated guidance on when
you think something might actually be closed and behind you? The announced deal
is one event, but if I remember correctly I think you were maybe suggesting at
least 6 to 10 months worth of regulatory review might be in order. Any sort
of sense that that might be fast-tracked, or is 6 to 10 months still a good
number?
Korell: I think it's as good a number as it is right now. We don't have any
reason to believe one way or another, and we haven't had any discussions or
contact with regulators that would guide that one direction or another. We would
hope to keep it to the shorter end. That's kind of the answer to that.
4. Could you remind me what your capital spending budget is for this year; in
other words, how much do you plan on spending for the rest of the year?
Kerley: Our E&P capital spending budget was $67 million. It originally started
off as $55 million if you remember, and we increased it by $12 million. A big
portion of that $12 million, I think about $6.5 million, related to the Overton
acquisition that we closed in the middle of the year. We plan to spend about $6
million that relates to the utility, and we expect to be pretty much right on
line with that for the year.
5. I was wondering if you could give some guidance in terms of fourth quarter
production and 2001 production? Also, if you expect expenses to change
significantly from third quarter levels?
Stevens: I think we're going to continue to see growth in our production in the
fourth quarter along probably the same rates that we've been seeing. We're
setting a minimum target for ourselves for next year of at least a 5% growth in
production, and hopefully we can achieve a lot more than that.
Expenses -- you know, as a whole industry we're seeing costs go up.
We've been doing everything we can. In some of our drilling costs we're seeing a
40% increase in rig costs, and in the field we're seeing a 30% increase in
costs, but we're doing everything that we can to keep it flat. But we think
we're going to be able to offset it with production. So, hopefully we can keep
it on a unit basis flat for next year.
Korell: One of the positive things that has helped us offset some of the
increases in costs of drilling the wells is that there seems to be a pretty big
thirst for quality prospects out there from lots of other companies, so we've
been able to promote people into drilling prospects where we're paying less than
our working interest share as we've done on some of those that we're currently
drilling. So, that's helped us quite a bit in offsetting the increased cost, and
that's basically the benefit of having the prospect generating machine that
we've had working here for the last few years.
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6. I want to make sure I understand this correctly. You state that you replaced
185% of production adding about 49 Bcfe. If I'm looking at your disclosure
correctly, it looks like you spent in the E&P area about $12.5 million; is that
correct?
Stevens: No. We have spent $53 million in E&P for the year-to-date.
7. Which makes sense. OK. So I guess that would imply just a little over $1 so
far this year. And I'm interested in your sense of a trend longer term that's
developing on this finding cost level. Clearly with prices in the $3 to $5
range, the finding cost can go up quite a bit and you still generate good rates
of returns like we saw yesterday in the Stone/Basin merger, which was in excess
of $2 per Mcfe, which probably made sense in this environment. But are you
seeing that kind of trend? A lot of your stuff is internally generated; can you
keep your finding cost, say, below $1.20 or $1.30, longer term? What is your
view?
Stevens: We're just now doing our budget for next year; but, yes, our finding
cost is going to go up because if you have the same size prospect and your
drilling costs are going up 40%, it's going to go up. Again, we're trying to
leverage ourselves to keep those down and try to keep as flat as possible, but I
do think there's going to be an increase next year. What percentage? That
depends on how well we can leverage ourselves going forward next year, but
they're definitely going to be going up.
8. On your Nodasaria test in Louisiana, you're saying that you reached the
total depth. Do you have well logs on that and how do they look?
Stevens: Yes. We've logged the well. In fact, they've cased the well and they
were yesterday displacing the fluids, getting ready to run the guns in to
perforate the Nodasaria target.
9. What do the well logs look like? Are you seeing a big section on there or
is it a lot of ratty sands?
Stevens: Well, the Nodasaria section looks fine. The deeper objectives that
we had hoped for were present but were wet. So we are coming back up to the
Nodasaria objective. But we think it will be a nice little discovery.
10. Al, you had talked about -- because obviously this was a good strong year
-- really good reserve replacement, but one of the things that I think people
might be a bit concerned about is rig availability and service availability. You
mentioned you've got a couple of rigs coming on in one of your plays. How do you
ensure that you have the equipment available to you to spend your capital budget
for next year? Have you tried to develop either some alliances or lock in some
rigs on a long-term basis or are you able to do that?
Stevens: Right now, in all three of our core areas, we're working at getting
into long-term contracts to guarantee that we'll have equipment availability
next year. That's been a real thing that we started on about a month ago, and
we're talking to contractors in all three areas.
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11. But you recognize that it seems like that's one of the key variables to
making the numbers work for next year in terms of growing production because
you'd need to have the rigs available to you.
Stevens: Yes, we recognize that and we're working diligently towards that end.
12. On Havilah and Malone, generally you kind of put out a net unrisked reserve
potential. Could you remind me what those are? And then also, I'm kind of
assuming that under Regulation FD you're going to put an announcement out on
these wells. Do you have any sense of when you might put a press release
out -- would it be a joint announcement on both of them, say, a month out or
six weeks or something?
Stevens: On Havilah and Malone, on unrisked reserve potential for our share, we
estimated Havilah at about 15 Bcfe and Malone at about 12 Bcfe. Again, those are
based on what we thought the most likely reserve size are. I would think in
Havilah within the next two to three weeks we'd be probably putting out
something on that. Malone, we're probably 30 days at least from total depth on
the well and seeing all the additional objectives, and a test on that would even
take it longer. So it may be towards the end of the year before we would have
anything on Malone.
13. You don't operate Malone, do you?
Stevens: Yes, we do.
Kerley: This is Greg Kerley again. We want to thank you for joining us this
morning. Feel free to call me with any questions that you may have. That
concludes our teleconference.
Operator: Ladies and gentlemen, that does conclude your conference for today.
You may all disconnect, and thank you for participating.
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