Southwestern Energy Company Conference Call Summary
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2000 Fourth Quarter Results Conference Call
Thursday, February 15, 2001
Chaired by
Harold Korell
President and Chief Executive Officer
Korell:
Good morning, and thank you for joining us today. With me are Richard
Lane, our Senior Vice President of Exploration and Production, and Greg Kerley,
our Chief Financial Officer. Al Stevens is with us also, by phone from Houston.
After some preliminary comments, I'll turn the floor over to Richard 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 have not received a copy of the press release announcing our
year-end quarter results, you can call Kathy at 501-582-8492, and she will 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 and involve risks and uncertainties, which are detailed in our
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.
First of all, I want to say that I am very proud of the results that we
were able to achieve in 2000. We'll talk more about those results in a few
minutes. But I'm also proud of our people, who stuck together through some
really tough times during this past year, and focused their energy on what we're
all here to do, which is to create shareholder value.
We ended the year of 2000 on a high note, both financially and
operationally. Financially, we had the best fourth quarter that the Company has
had in seven years. We reported operating results in early February for our E&P
segment, and they were outstanding. On top of that, our stock price increased
61% during 2000. I'll let Richard and Greg talk in more detail about our
results, but I wanted to touch on just the high points.
1. Our production was up over 8% in 2000, after a decline of 11% in
1999.
2. Our finding and development cost for 2000 was $0.99 per Mcfe, and
we replaced 196% of our production with over 70 Bcfe of new
reserves.
3. Our drilling program is hitting on all cylinders, with solid
performance from our Arkoma and Permian Basin programs, and
meaningful success in our exploration
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efforts in South Louisiana, where we have now been successful on
the last four out of five wildcats.
4. Our reserve base increased 7% during the year, and ended at 380
Bcfe.
5. Finally, our outlook for 2001 is equally positive, with 80% of
2001 gas hedged at attractive prices, we expect significant
increases in our financial results and are focusing on improving
our balance sheet.
As for our utility operations, there's been no change in the status of
the sale of our utility assets. We are comfortable holding these assets, as they
continue to provide a solid stream of earnings and free cash flow that we can
use to reduce debt.
Overall, I'm very pleased with our results in 2000, and I'm looking
forward to a great year in 2001. We've gained significant momentum with our E&P
strategy, and we're very focused on doing the right things to add value for our
shareholders.
Just a final note about the appointment of Richard Lane as the new head
of our E&P operations. As many of you know, I brought Al Stevens and Richard
Lane here in early 1998 to rebuild our E&P program. I'm very proud of the job
they have done to turn our E&P business around, and get it to where it is today.
However, for some time, Al has expressed a desire to have more time to devote to
things other than Southwestern Energy. With the arrangement we've made, Al can
spend more time with his family, yet we will still retain his knowledge and
expertise on a part-time basis. I want to say that I am grateful for all that
Al's done for the Company, and I value him as a true friend. I also have
complete confidence in the abilities of Richard Lane and the team we have put in
place to grow our E&P program from where it is today.
That concludes my comments at this time, and I'd like to turn it over
to Richard to give us an update on the E&P operations.
Lane:
Thank you, Harold. The fourth quarter of 2000 brought to a close what
was one of the most successful years ever for the Company's E&P segment. For the
full year, we were able to successfully replace 196% of our production with 70.1
Bcfe of new reserve additions. These additions were made at an average finding
and development cost of $0.99 per Mcfe. Production was 9.1 Bcfe for the fourth
quarter, up from 8.3 Bcfe for the same period in 1999. Production for the full
year of 2000 was 35.7 Bcfe, as compared to 32.9 Bcfe in 1999. This corresponds
to an increase in production of over 8% from year-to-year.
The Company's oil and gas reserves at year-end 2000 were 380.5 Bcfe, up
7% from year-end 1999. In total, we participated in 105 wells in the year, of
which 78 were successful. We continue to create value with our Arkoma Basin
development program. Of the 42 wells drilled in 2000 in that area, 32 were
productive, and one was drilling at year-end. Two fourth quarter wells in our
Haileyville prospect are of special note. The Collins #1-13, which is currently
producing 7.2 million cubic feet a day from the Middle Atoka Sands, and an
offset well to the Collins, the Agnes #1, which reached total depth earlier this
month. Logs indicate that the Agnes will also be
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a strong producer. Southwestern has approximately a 46% and a 37% working
interest, respectively, in these two wells, which are really excellent examples
of the kinds of opportunities our experienced Arkoma team is generating.
In the Permian Basin, we completed the development of our Bimini
discovery in Lea County, New Mexico, with the drilling of our fifth well. These
five wells are currently producing at a combined gross rate of 448 barrels of
oil per day, and approximately a half a million of cubic feet of associated gas.
Southwestern's working interest in these wells range from 55% to 100%.
We have recently made another discovery in the Permian Basin. The first
well on our Cowden Ranch prospect successfully penetrated approximately 20 feet
of pay in the Lower Devonian formation, and 67 feet of pay in the Upper
Devonian. After completion of this first well, we anticipate drilling follow-up
development wells. Additionally, we are planning other wildcats on the Cowden
Ranch area in 2001. The Cowden Ranchh project area is located in Crane County,
Texas, and we operate and have about a 92% working interest.
In 2001, we have dedicated resources to continue our growth in the
Permian Basin, with a plan that includes the drilling of 19 exploratory and 6
development wells. We currently have 4 of those exploratory tests drilling, as
of today. We're also continuing to strengthen our land position in the Permian
Basin. We recently announced two joint exploration agreements in southeast New
Mexico, which increased Southwestern's total control leasehold position by
35,000 net acres. The first agreement, with Energen Resources, included
approximately 14,200 net acres in Lea and Eddy Counties. Additionally, we were
able to negotiate a second exploration agreement with Phillips Petroleum
Company, including 21,100 new net acres in Eddy County.
At our Overton Field in Smith County, Texas, we have initiated our
development drilling program. We are currently completing our first well, and
are drilling ahead on an additional well. We anticipate drilling 8 - 14 wells in
the Overton Field this year, and these are targeting the lower-risk Cotton
Valley Sand objectives.
In South Louisiana, we have continued our exploration success. At our
last teleconference in late October, we were drilling on our Havilah and our
Malone prospects. Since then, we have announced that both of these prospects are
discoveries. Our Havilah prospect was brought on production in December, and is
currently producing 7.2 million cubic feet of gas per day and 317 barrels of oil
from the Nodosaria formation. Southwestern operates this Lafayette Parish well
with a 27.5% working interest.
At our Malone prospect, in Assumption Parish, we penetrated and logged
approximately 260 feet of pay in five separate productive sands within the
Miocene. This is an exciting confirmation of our pre-drill exploration concept.
We are currently testing the lower most of these sands. Southwestern operates
this prospect with a 33.3% working interest, and we anticipate this well will be
on production late this month. After drilling the first well, we immediately
relocated the rig to drill an offset development well. We have just reached TD
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(total depth) on that development well, and we'll be logging and evaluating it
over the next few days. We anticipate first production on that well sometime in
April.
In 2000, we were successful in making discoveries on three of the four
wildcats that we drilled in South Louisiana. In 2001, we plan to drill nine
additional wells, including six exploration wells and three development wells.
Southwestern's exploration and production capital budget for 2001 is
$75 million. We continue to be very active in the Arkoma Basin, Permian Basin,
Gulf Coast, and at our Overton Field. Approximately 75% of this capital will be
dedicated to drilling, which lets us maximize the potential impact of our
investment dollars. The remainder will be invested in our ongoing land and
seismic acquisition programs to fuel our future growth. We project that
Southwestern will participate in approximately 120 wells in 2001.
Overall, we are very pleased with the results of 2000. We successfully
increased both production and reserves, and I'm also very enthusiastic as we
enter 2001. We continue to have a strong inventory of internally-generated
prospects, in both the Permian Basin and Gulf Coast areas, and are off to
another good year on the Arkoma Basin. We also have significant exploitation
opportunities in the development of our Overton Field, and several of our most
recent discoveries.
That concludes my report. I will now turn it over to Greg Kerley, who
will discuss the financials.
Kerley:
Thank you, Richard, and good morning. As Harold indicated, we reported
net income of $9.1 million, or $0.36 a share for the fourth quarter of 2000,
which is double our reported earnings for the same period last year. Cash flow
from operating activities, before working capital changes, was $27.7 million
during the fourth quarter, up almost 90% from $14.7 million in the fourth
quarter of 1999. For the year 2000, before unusual and extraordinary items, we
reported net income of $20.5 million, or $0.82 a share, more than double the
$0.40 a share we reported in 1999. Cash flow, before unusual items and changes
in working capital, also was up dramatically to $82.4 million, versus $60.8
million in 1999.
Our results were primarily driven by higher production volumes that
Richard discussed, and by higher commodity prices that the industry has enjoyed
over the past year. Operating income for our E&P segment, before unusual items,
was $40.7 million in 2000, up from $16.5 million last year. These results would
have been even stronger, except that we had a significant amount of fixed-price
commodity hedges in place during the year at $2.38 per Mcf.
Fortunately, these hedges have rolled off and, going forward, we will
enjoy higher realized prices as our current hedges are much more favorable. We
continue to be about 80% hedged for our 2001 gas production target, and there
has been no change in our hedge position since our press release on December
7th. If you need a copy of the press release that details our hedge position,
I'll be happy to send it to you. It can also be found on our website.
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Including the effect of our hedge volumes, we realized an average price
of $2.88 per Mcf for our gas production, and $23 per barrel for our oil
production during 2000. Again, we expect that our average prices in 2001 will be
up substantially from what we realized this past year.
Production and operating expenses for the E&P segment, while still some
of the lowest in the industry, rose during 2000 due to increased production
volumes and an increased number of workovers that were performed to take
advantage of the higher commodity prices. Our lifting cost, on an equivalent
unit of production basis, was $0.40 per Mcfe in 2000, compared to $0.35 per Mcfe
last year. Higher oil and gas prices also affected our production taxes, as they
increased to $0.15 per Mcfe in 2000 from $0.09 per Mcfe last year.
Depreciation, depletion and amortization expense for the E&P segment
was up in 2000 due to higher production volumes and a higher amortization rate.
The amortization rate for the full cost pool in 2000 averaged $1.06 per Mcfe, as
compared to the prior year rate of $1.00. The level of the unamortized portion
of our full cost pool has steadily declined since 1997, and we're happy that
it's down to about $28 million at this point.
Our gas distribution segment continued its solid contribution with
$14.7 million in operating income in 2000, compared to $17.2 million in 1999.
The comparative decrease is due to a couple of reasons. As you may recall, we
implemented a $1.4 million rate reduction in December of 1999, and we sold our
Missouri utility properties in May of 2000. We continue to be very pleased with
the improving efficiency and cost control that has taken place at the utility,
and these assets continue to provide about $8 to $10 million of free cash flow
each year, that we can use toward reducing our debt.
Our energy marketing efforts also provided about $2.5 million of
operating income in 2000, up from $2.1 million in 1999. Due to our increased
debt level related to funding the Hales judgment, our interest expense is up
about 34% in 2000. Our debt does, however, continue to carry a very favorable
interest rate, which currently averages about 7%.
At year-end, our capital structure was about 74% debt-to-total capital.
We are focused on improving our capital structure as quickly as possible, and
with the combination of higher production, higher commodity prices and our hedge
position, we are targeting reducing our total debt by $50 to $70 million in
2001. Our capital expenditures totaled nearly $76 million during 2000, with our
E&P segment accounting for over 90% of that amount. Our capital budget for 2001
includes $75 million for exploration and development, $6.1 million for utility
system improvements, and $0.4 million for other purposes.
Well, that concludes my comments, and 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. First, operationally, what was the performance in the Permian last
year, or a success rate? I know that you gave us your total drilling
success, but what about your Permian results?
Lane: In the Permian Basin, we drilled 57 wells, of which 43 were productive,
so it was about a 75% success rate. Overall, if you look at the region,
the reserve additions and the capital, including our Overton area,
we're at about $0.92 per Mcfe for the year.
2. A $0.92 finding cost is your whole Permian and Overton combined?
Lane: Correct.
3. Are you looking at more joint venture opportunities, or is it you have
enough on your plate, with enough acreage, for now?
Lane: You know, we're always looking for more land resources in that part of
the world. But, the ones that we have in front of us here give us a
good basis for our inventory through 2001 and on into 2002. But we'll
continue to look for more of these opportunities, yes.
Korell: I think the other comment on that would be one that we've made before,
in regard to our strategy in Oklahoma, and that is at some point, if we
could find the right assets in the Permian that had further
exploitation or development opportunities on it, we would like to sell
our Mid-Continent properties and buy in the Permian, or trade.
4. Moving over to South Louisiana, could you do that same breakdown on F&D
in South Louisiana, in terms of expenditures there and reserve adds?
Do you have that?
Lane: The pure reserve additions for South Louisiana for the year are
approximately 22 Bcfe. Those do not include the recent Malone discovery
that we just talked about. And the finding and development costs, with
the associated capital there, is about $1.11 per Mcfe. We have some of
the capital for Malone in 2000, but not the reserves.
5. On the utility side, of course this quarter, really good results
there - probably somewhat due to prices and weather. How do we expect
that going forward, in terms of repeatability? Is there something
fundamentally that's going to carry through the first quarter, or do we
see it go back to more typical first quarter-type results?
Kerley: Well, I think it would be pretty typical for first quarter results, so
far what we're seeing. Which is nice, compared to the last couple of
years. We had some really good cold weather in November and December,
which really helped us. On a go-forward basis, the utility will
continue to contribute about $20 million of EBITDA, and about $13 to
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$14 million of net operating income. We'll still produce from that $8
to $10 million of free cash flow on a recurring basis. It's fairly
consistent. The growth is still very strong, here in the northwest
Arkansas territory. It is earning its allowed return effectively and,
we continue to make sure that we're doing that, and expect to control
costs to where we continue to earn that return. Or, as necessary, file
for a rate case, to make sure that we do.
6. It seems like the realizations were a little less that I would have
expected, even with the hedges built in. Does that result from some of
the inter-company eliminations, or did the utility benefit from some
lower price gas that was purchased directly from your E&P segment?
Kerley: No, if you look back at our hedge position, we still had a little bit
of hedges at $2.38, and we also had some other collars that were in
effect that kept us from realizing full price.
Korell: Certainly through the third quarter.
Kerley: Yes, in the third quarter, very heavily, and in the fourth quarter we
still had hedges that affected what we realized. Rolling into 2001,
that's significantly improved, and we'll realize much higher prices.
7. Could you give me a breakdown of the reserve adds, how much of that
would have been attributed to drilling versus acquisitions, and what
were positive revisions during 2000, if you had any?
Lane: The reserve adds for the year were approximately 18 Bcf from the
Arkoma region. Again, about 22 Bcfe in South Louisiana, then 30.1 Bcfe
in the Permian, including the Overton acquisition. And the Overton
reserve adds, that would be the non-drilling part - I think we're about
19 Bcfe. So, about 19 Bcfe of the total 70 Bcfe would have been from
acquisitions, the rest from drilling. In terms of our year-end reserve
picture, I think our total upward revisions, net of performance, was
about 5 Bcfe.
8. Was that driven by price?
Lane: Partially by price, and some downward revisions for performance.
9. And then, LOE on an Mcfe basis, was up. Is that mainly because of
workovers?
Lane: That's right.
10. Got a question about the Malone well. Do you have any test rates from
that well, yet?
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Lane: We don't have any test rates on that. As of today, we have operations
in the field on that first well. They would be close to testing it, as
we speak, so you'll see some things from that in the near future, and
the production associated with that well.
11. And then, the follow-up well to the Malone. Is that going to confirm
the 50 Bcfe target, or reserve size, or is that going to increase that?
Is there potential upside there?
Lane: The second well is primarily designed to accelerate some of the sands
that we found productive in the first well. We have so many productive
sands that, economically, it makes sense to accelerate some of those,
and that's what that second well was designed for. It shouldn't
materially impact the reserves, as we see them now.
12. And then, just about 2001 guidance. You had a conference call toward
the end of December, and I just wonder if there are any updates there,
in terms of what you're expecting for 2001 production, earnings, etc.
Kerley: I think what we put out a few weeks ago is accurate. I don't think
there's a big difference in any of those numbers. I think the operating
costs, you know, what we predicted for 2000, for what we would average,
we ended up a little bit higher. And we may see a little bit of
inflationary pressure that we're seeing across the industry, that might
impact a little bit on an Mcf equivalent basis. But we're happy with
the forecast information that we put out before.
13. On the income statement, the "Other Income" number in my model was
lower. What was driving that? Is there anything unusual going on there,
or is that an ongoing level, a couple million positive, for the year.
Kerley: There were a couple of unusual things that happened there. We had
some recoveries on some things. First, we sold Missouri - that was the
biggest impact. There's a $3 million gain on our Missouri assets in
there. We sold some small amount of assets, inventory-type things, that
we recorded a little bit of gain on. So, going forward, it probably is
higher than it would be, maybe by $1 to $2 million.
14. This Devonian thing in Crane County. I know there's been some
success out there, by a couple of companies, on this kind of horizontal
Devonian play. Is that what we're looking at here, or is this just kind
of classic vertical Devonian holes, and definitely new, here?
Lane: No, it's a different project, I think, than some of those you are
familiar with. This is a shallower horizon that we're targeting, and we
believe they're oil productive. So, a little further south in the
basin.
15. But this is a pretty new play for you guys. I mean, what kind of
acreage position do you have out there?
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Lane: Yes, it is a new play. It's an area that we've been able to secure
some 3-D seismic and acreage over a large part of the ranch. I think
it's approximately 10,000 acres that we have either leased or optioned,
that cover the heart of the play.
16. Just, in terms of depth, what's the target?
Lane: We'll be looking for prospects from the shallowest, 5,000 feet, down to
about 10,000 feet.
17. Just a question on the 120-odd wells that will be drilled this year.
Can you give us a sense as to what sort of reserve exposure that
provides for you, in terms of potential reserve adds? I guess it would
be unrisked net reserves, what sort of potential is that going to give
you?
Korell: Our exploration program, primarily Permian and Gulf coast area, the
number is in the range of 260 to 270 Bcfe, in the exploration arena.
And that doesn't include anything for any exploration or development
which we will be doing in the Arkoma. We tend to be able to book about
15 to 20 Bcf there with that program. So, that's a fairly safe part of
it. That 260 or 270 Bcfe doesn't include any Overton reserves either,
where we'll be doing infill drilling. But just the exploration side of
it, 260 to 270 Bcfe, more or less.
18. And with the capital, I'm trying to remember the capital you'll be
spending on drilling for the E&P side?
Korell: Well, our total capital for E&P is about $75 million, and three-fourths
of it will go to the drill bit.
One comment, since we're talking about potential reserves. Richard was
answering a question earlier about acquisitions versus drilling. And I
guess, it would depend on how one wanted to view Overton. I think he
said there was 19 Bcfe, or something like that, and looked at Overton
as an acquisition. When we did the acquisition, my recollection is
there was about 6.5 to 7 Bcfe booked to the acquisition. And then, what
we've done, is booked some incremental to that, of proven undeveloped
locations to drill. And, if you remember, that's primarily drilled on
640-acre spacing, and we're beginning the infill drilling program, now.
19. Okay. So, you will get some additional reserve adds there, over time.
Korell: Yes. I wanted to clarify that, for whomever it was that was asking, if
they were trying to quantify drilling versus acquisitions. I don't know
how they would themselves want to put that category in, but primarily,
we've been a drilling Company, not an acquiring Company.
20. Greg, what are the differentials looking like, on a pre-hedge basis,
currently, for both oil and gas?
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Kerley: Well, on a pre-hedge basis, we're real close to the NYMEX price right
now, on our realizations, to maybe a few pennies above that. That's an
overall average. On the gas side, you know, maybe a +$.05 per Mcf type
of deal. On the oil side, we work from about $1.00 to $2.00 back from
the posted price.
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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