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Filed by: Chesapeake Energy Corporation
Pursuant to Rule 425 of the Securities
Act of 1933, as amended
Subject Company: Gothic Energy Corporation
Commission File No.: 0-19753
CHESAPEAKE ENERGY
MODERATOR: AUBREY MCCLENDON
JULY 28, 2000
8:00 AM CT
Operator: Good day everyone and welcome to the Chesapeake Energy Second Quarter
Earnings conference call. This call is being recorded. At this time for
opening comments and introductions, I would like to turn things over to Mr.
Aubrey McClendon. Please go ahead, sir.
Aubrey McClendon: Good morning and thanks for joining us today on our second
quarter earnings release conference call. Before we begin, I need to
provide you with some disclosure concerning the forward-looking statements
that we will make during the course of this call.
These forward-looking statements that describe our beliefs, goals,
expectations, projections, or assumptions are considered forward-looking
statements. Please note that the company's actual results may differ from
those contained in such forward-looking statements. Additional information
concerning our forward-looking statements is available in the company's SEC
filings.
I'll begin with a general overview and then turn the call over to Marc for
his comments. After that, we'll go to Q&A.
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I'll begin with the highlights - we earned $32 million in net income,
generated an operating cash flow of $60 million and produced EBITDA of $82
million. All of these achievements are records for our company.
In addition, our oil and gas production for the quarter was 34.1 billion
cubic feet of gas equivalent or an average of 375 billion cubic feet of gas
equivalent production per day. Eighty-six percent of this production was
natural gas which was our highest percentage ever of natural gas
production.
With regard to production, I'd like to emphasize that our gas volumes were
up 8.5% over the year ago quarter and up 2.1% over the 2000 first quarter.
This was our sixth quarter in a row of sequential gas production growth. In
an industry where production growth has been and remains elusive, we are
particularly pleased with our performance and continuing to grow
Chesapeake's gas production.
Our next big production increase will of course come from Gothic where
production levels are currently around 80 million of cubic feet of gas
equivalent per day, 96% of which is natural gas itself. We anticipate
beginning to book Gothic's volumes right at the beginning of next year.
Operationally, we are continuing to execute on the business strategy that
we consistently described for our investors during the past two and a half
years. This business strategy is a simple one. We aim to be the best
explorer, developer, and producer of natural gas in the Mid-Continent, the
area of our primary focus.
In addition, we expect to also to be the best in the three smaller areas
where we operate. As a reminder, these smaller areas are the Helmet field
in Canada, the Giddings field in Texas, and the Lovington area in New
Mexico.
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In each of these operating areas, we believe the combination of our
operating scale, geological expertise, and large land inventory provides
Chesapeake with significant competitive advantages; advantages that enable
us to create significant value through our drilling and acquisition
programs.
These operating strengths should be most obvious to you in the quality of
our cost structure. We believe our cash costs which consists of 10 cents
per MCFE for G&A, 37 cents for lifting expenses, and 17 cents per MCFE for
production taxes during the second quarter are the lowest of the 30
companies we benchmark ourselves against in the mid-cap and large-cap E&P
universe.
We believe these numbers reflect a high degree of asset quality and also a
management team that is very focused on controlling costs. I would also
like to emphasize that our finding costs continue to remain very low as
well which we believe also reflects favorably on the quality of our assets
and operational teams.
Last year, you may remember that we replaced our production by 187% at a 65
cent per MCFE cost. During the first six months of this year, we have more
than kept pace with last year's success, replacing our production by more
than 200% at a cost significantly less than our target for the year of 85
cents per MCFE.
Although we are clearly seeing higher drill bit finding costs, the effect
to date has only been about 10% to 15% per well. Although we will probably
see further increases in drilling costs in the months ahead, we still
believe we can beat our drill bit finding cost target for the year of 85
cents per MCFE.
And with Gothic reserves rolled in at $1.05 per MCFE at the end of the
year, we believe our overall finding cost for 2000 will be under a dollar
per MCFE. This will translate into a reserve
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replacement of almost 400% which we believe will prove to be one of the
better performances in the industry this year.
Balance sheet improvement continues to be a major focus of our management
efforts. As Marc will describe in more detail in a few minutes, we have
reduced our fixed obligations this year by more than $150 million, and in
addition, we believe that our cash flow this year and next should be at
least $100 million in excess of our drilling land and seismic budget. This
should provide us with the opportunity to continue improving our balance
sheet while at the same time, enabling us to continue growing our reserves,
production, and profitability through disciplined capital allocation
policies.
In conclusion to my portion of our comments, I'd like to reiterate that we
have a single-minded focus at Chesapeake on enhancing shareholder values.
We believe we can best accomplish that through developing high quality
natural gas reserves principally in the Mid-Continent area.
This is where we have carved out a profitable niche for Chesapeake and have
developed a substantial inventory of drilling and acquisition
opportunities. We believe our successful execution of this strategy will
lead to continuing increases in shareholder value in the quarters ahead.
I'll now turn the call over to Marc and then we'll move to Q&A.
Marc Rowland: Thanks, Aubrey and good morning. I'd like to begin by discussing
the status of Gothic Energy Corporation. On June 30th, as you are aware, we
announced our intention to acquire Gothic by merger.
Since that time, Chesapeake and Gothic have been working to complete the
definitive merger agreement that Chesapeake has been working to obtain a
backstop credit facility to enable us to
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complete the merger. At this time, neither of the agreements are signed but
we intend to complete both within one week.
On July 7 we filed an S-1 Registration Statement covering the CHK common
shares issued in connection with the purchase of the Gothic senior discount
notes. We have heard from the SEC and they've indicated that they intend to
only conduct a limited review of the filing. We expect to complete the
review process by the middle of August, after which the S-1 Registration
Statement will be declared effective.
Our current schedule with Gothic is to have both companies June 30th
Quarterly 10-Qs filed by August 4. And assuming executed definitive merger
agreements with financing in-hand to follow an S-4 Registration Statement
on or about August 11th with the SEC.
Of course it's impossible to predict whether or not the SEC will choose to
review the S-4. Whether reviewed or not, once declared effective, the proxy
material will be distributed to the Gothic shareholders for a vote which
normally takes 30 to 40 days after the proxy material is distributed. All
of this leads us to estimate that the merger could be completed as early as
mid-November but probably in the first weeks of December of this year.
Turning back to the quarter just ended, a real highlight for Chesapeake was
our progress in reducing our obligations further by exchange of CHK common
stock for our preferred. In this quarter alone, 2.36 million shares of
preferred stock were exchanged having a face of value $118 million and $132
million, including the dividends that have accrued but were still not paid.
In exchange for that preferred stock, we issued just under 25 million
shares of common.
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Approximately 1.55 million shares of the preferred remain at this time, or
$78 million in face value. That reflects a two-thirds reduction of the
original $230 million, and we have reduced our annual dividend requirements
on the remaining $78 million to just over $5.5 million.
I would remind you that the preferred stock is first callable by the
company May 1 of 2001 and it can be called, including the accrued
dividends, by the company issuing common stock.
We expect to sign our new bank facility on July 31st. This will be a $100
million revolver with a maturity of August 15, 2002 at which time, the
revolver will convert into a term facility at our option, further extending
the maturity of the facility to January 15 of 2003. We welcome Bear Stearns
Corporate Lending as co-lender in this new facility.
Turning to some of the financial details for the quarter that were not
covered in the press release, our capital expenditures for the quarter just
ended were right on budget. Our drilling expenditures including capitalized
costs were $35 million. Acquisitions were $20 million, for a total of $55.5
million.
At June 30, we had a cash position at just under $17 million with $63
million outstanding on our credit facility with the banks, leaving net debt
at that time of $46 million.
During the quarter, the company capitalized $600,000 of interest --
significantly less than last year. And for the first six months of the
year, the total capitalized interest was $1.3 million. Capitalized internal
costs including all of our drilling, labor, overhead, and so forth was $1.5
million for the quarter or $3.4 million for the first six months.
Rather than dwell on the details already contained in the press release, as
is our policy we will go to questions and answers at this time.
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Operator: Gentlemen, thank you very much. Today's question and answer session
will be conducted electronically. If you would like to ask a question, you
may do so by pressing the star or asterisk key followed by the digit 1 on
your touch-tone telephone. Again that's star 1 on your touch-tone telephone
for questions. We'll pause just a few moments to assemble the roster.
Please stand by.
We'll take our first question of the day from Gary Stromberg, JP Morgan.
Gary Stromberg: Hi, guys. A couple questions here. It looks like production in
the press release, at least forecasted for 2000, you're calling for 136
BCFs. Am I right in concluding that that's down a bit from the previous
estimates of 138 to 142?
Aubrey McClendon: Yes, it is. We - our previous guidance had been 138 BCFE. And
we basically pulled it in to be flat to where we are today with the idea
being that through the course of the year, we'll make fewer, smaller
niche-type acquisitions that we had previously budgeted on to take our
production up a little bit in the third and fourth quarters.
So we would just have everybody pull in production forecasts a little bit
to 136 which is equivalent - which is basically flat from where we are
today.
Gary Stromberg: Okay. And can you review acquisition activity in the first half?
I guess dollars spent and BCFs.
Marc Rowland: I can Gary. I have the details of that. I guess you're talking
about the total amount of expenditures?
Gary Stromberg: That's right.
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Marc Rowland: To date, January 1 through June 30, we have spent $23.6 million on
acquisitions. The acquisitions have been very attractive from a standpoint
of reserves purchased. $20.2 million dollars of that was accomplished of
course in the second quarter.
We believe that the acquisitions have added proved developed producing
reserves of about 35.6 BCF in that six-month period of time. The trend
there we think is of course up, although we continue to have very
attractive opportunities presented to us right in our Mid-Continent area
with the many wells that we operate from other non-operators.
Gary Stromberg: And how big do you think you'll go on these acquisitions? Are
they still going to be, you know, five to ten or do you go higher?
Marc Rowland: Well of course the Gothic merger announcement changed the
composition of our entire focus. As Aubrey mentioned, we are pulling back
from cash allocations for the smaller acquisitions to focus on the cash
portion of the Gothic transaction being as large as possible for debt
reduction, so the focus has changed. We'll continue to be presented with
$1, $2, $5 million acquisitions but they have to measure up to the Gothic
acquisition really from a standpoint in the next six months to be really
compressed to allocate capital to.
Gary Stromberg: Okay, great. Thanks.
Operator: Bruce Wilcox, Cumberland Associates.
Bruce Wilcox: Yeah, hi. I'd just like to quickly review the balance sheets both
as it exists now and pro forma for the acquisition. With the remaining
preferred shares, what is the conversion value in common of the remaining
preferred?
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Marc Rowland: The conversion rate is $6.95 a share, which yields 7.19 shares of
common for each share of preferred. That would be about 11 million
shares...
Bruce Wilcox: On the remaining 1.55 million preferred...
Marc Rowland: That's correct. And that...
Bruce Wilcox: So was that number - 11? Sorry.
Marc Rowland: I can give you the exact number here. It's 11 point something.
Bruce Wilcox: That's close enough. And then what was the share count at the end
of the quarter also pro forma for any subsequent exchanges of preferred?
Marc Rowland: The actual common outstanding at the end of the quarter was
approximately 139.5 million shares.
Bruce Wilcox: Okay. And has it been - since the quarter end, has there been any
subsequent exchange?
Marc Rowland: There has not been any subsequent exchange.
Bruce Wilcox: So pro forma for the conversions, the remaining preferred, it
would be about 150 million shares.
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Marc Rowland: It's 11.1 million is the exact number of convertible shares. And
so added to the 139 it would - you're right, it would be just over 150
million.
Bruce Wilcox: And then could you just simply review, you know, the broad terms
of the acquisition of Gothic in terms of net debt assumption, number of
shares issued, in ranges, if necessary?
Marc Rowland: Yes. It's real simple. We are going to issue four million shares
of common stock for all of the Gothic shares outstanding as of the date of
the merger.
Bruce Wilcox: Okay.
Marc Rowland: We at that time will be assuming $235 million of senior secured
notes that are held in Gothic Production Company, the wholly-owned
subsidiary of Gothic Energy.
It's our estimate that cash flow from operations in conjunction with our
understanding of their capital expenditure program right now, that they
would have sufficient cash on-hand to either eliminate or to have offset
the small amount of bank debt. So we assume, December 1 that we will only
be assuming $235 million of debt.
Bruce Wilcox: Okay. So that's it - four million shares and $235 million of debt
estimated?
Marc Rowland: That's correct.
Bruce Wilcox: Okay. And then what was the Chesapeake net debt or the total debt
and then total cash position at the quarter end?
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Marc Rowland: Well we had $920 million of senior unsecured notes outstanding.
And our net other debt as I mentioned was $46 million.
Bruce Wilcox: Okay. So...
Marc Rowland: That gives you $966 million.
Bruce Wilcox: Right. Okay. That's great. Sounds like you had a nice quarter.
Marc Rowland: Okay, Bruce.
Operator: We'll go on to Steven Smith, Dain Rausher Wessels.
Steven Smith: Yes. I missed the first couple of minutes so I hope I'm not asking
something that was already discussed. But can you talk a little bit about
the composition? You had mentioned that you had already replaced your
reserves for the whole year based on your half year's of drilling effort
and the cost was below your 85 cent target.
Could you talk a little bit - and I presume that excludes the whole Gothic
deal because - but could you talk a little bit about the composition of how
you did that?
Aubrey McClendon: Steve, most of it was through the drill bit. As Marc
mentioned, the reserves that we've added through acquisitions are about
36...
Marc Rowland: Thirty-five and a half...
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Aubrey McClendon: Yeah, 35.5 BCFE. So we believe we are north of 200% of what
we've produced today which is 68 BCFE. So, quick math is about
three-quarters has been through the drill bit and one-quarter through
acquisitions.
Steven Smith: And what would you say - how would you describe what's happened to
your drill site inventory? Sort of what you thought it was at the start of
the year based on drilling experience so far this, how that's been changed?
And then finally, what Gothic does to your drill site inventory?
Aubrey McClendon: Steve, we were very active during 1999 when other people I
guess weren't so active in further building our land base. So we entered
the year with actually more acreage than we had at the beginning of 1999.
We began the year 2000 with more acreage. We added geologists through the
year, landmen through the year and engineers as well in anticipation of a
rebound. Obviously the rebound caught us a little earlier than we thought
it would come and probably with a little bit more velocity than we thought,
but we really thought it would come.
So I would say that overall, our land base and drill site inventory has
actually increased through the course of the year. And that's just assuming
flat pricing with prices that we have today. Obviously some things looked
attractive to us that just probably didn't in 1999 or '98.
One of the main attractions of Gothic is the drill site inventory that they
bring which is completely complimentary to what we have ourselves. Through
the most part - well no, almost exclusively, we had an interest in every
drill site that Gothic brings to the table. We are now able to essentially
double that - the working interest that we have in each of those prospects,
because you may recall from the initial Gothic deal, we ended up with 50%
of their leasehold - of their - under a leasehold.
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So we had 50% now we'll have 100%. So we were very, very familiar with
these drill sites and are happy to own 100% what - wherever we can.
Steven Smith: Okay. Thanks Aubrey.
Aubrey McClendon: Yeah. Thank you Steve.
Operator: Our next question comes from Ellen Hannon, Bear Stearns.
Ellen Hannon: Good morning.
Marc: Hi Ellen.
Ellen Hannon: Hi. Most of my questions have been answered but I - just a quick
one on your hedging Marc. The forecast that you've given here on the third
quarter hedge on gas $2.93 NYMEX, that would be before your basis
differential which you're assuming at about 31 cents?
Marc Rowland: That is correct.
Ellen Hannon: Okay. I think I got everything else. Thank you.
Marc Rowland: Thanks Ellen.
Operator: Tom Parker, Chase Securities.
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Tom Parker: Hi. Can you give us some idea of how we're being set up now for
2001? And if you want to talk with Gothic or without Gothic, that's fine.
But in terms of production growth for that year given, you know, how things
are starting to set up now?
Marc Rowland: Sure Tom. We have laid out numbers that basically assume that
Gothic's production, currently around 80 or 81 million a day, remains flat
throughout 2001. That's a production pro forma of around 30 BCF equivalent.
We've stated without any additional acquisitions, that our core growth rate
will be a few percent. We're looking at about 140 to 145 BCF from our own
production.
So just totaling those two together, the year sets up as 170 plus BCF
equivalent looking into next year. Of course, operating costs will drop as
a result of Gothic's operating costs being slightly lower than ours. DD&A
rate will increase as a result of our acquisition being layered in at just
over $1 an MCF on their 300 plus BCF of reserves.
We think there will be G&A efficiencies and all of that will lead to a 9 or
10 cent G&A number for us on a pro forma basis next year. Interest costs
will be up as a result of adding additional debt and preferred dividends
and other fixed charges will be down of course.
So those are the core constituencies of how we're going to set up for next
year. If you have any additional specific questions - I'd also add that we
don't anticipate any cash taxes. Our only deferred taxes right now are
being generated in Canada and those are all deferred as well.
Aubrey McClendon: Tom, I might chime in with one other thing. The production tax
number will probably continue to creep up a little bit as well as wellhead
realizations increase in the second half of this year and 2001.
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Tom Parker: And the production taxes, that's all revenue side or are you
getting some change in mix that's leading the absolute rate up?
Aubrey McClendon: It mixes a little bit. Oklahoma's production tax rate is
7.01%. And Texas' gas production rate for example is just about 5.5%. We do
have - we do take advantage of various severance tax exemptions and
holidays that are out there. I think we've budgeted overall for about 5.5%
off the top for production taxes. And we recommend that you all use that
number for an overall corporate rate.
Tom Parker: Okay. And your thoughts on the capital structure post-Gothic, let's
say assuming that the bonds aren't put to you? You know, would you like to
do equity? Would you like to do debt? I assume you wouldn't want to leave
senior secured in place?
Marc Rowland: Our thoughts on the capital structure haven't really varied. We
don't mind leaving the senior secured in place. Gothic has an unrestricted
subsidiary with the joint ventures in place. We think we can operate that
entity without any obstruction to our business plans at all. The company
has a right to take all of the drilling locations and drill those. We can
also leave part of the drilling locations inside of the company and use
their cash flow for that.
First call on the notes is May 1 of 2002. We would like -- if we just could
draw on a chalkboard -- we'd like to bring over about $150 to no more than
$175 million of incremental debt either using operating cash flow between
now and the merger, or between now and shortly after the merger to reduce
some of that debt either through open market purchases or having the notes
put to us. And we would either - we would consider using some equity either
to purchase the notes or to issue notes and then use the cash proceeds.
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But our ideal capital structure by May 1 of 2001 would be to have the
preferred stock converted into common either through continuation of
unsolicited offers to us or first call on the preferred, to see our own
secured debt stay in place at $920 million and add no more than $170
million of Gothic debt in the merger. That would take us to pro forma fixed
obligations of $1.1 billion against reserves that we see at that time of
1.6 to 1.7 TCF.
Tom Parker: Okay.
Marc Rowland: That's the ideal structure.
Tom Parker: Okay. And then finally, can you give us some color on the coal bed
play, you know what kind of spending you're thinking of and how these maybe
differ from the Powder River-type play?
Aubrey McClendon: Sure. And for those of you who might have missed it, we
announced, ten days or so ago, that we had entered into a joint venture
covering 2.2 million acres in the Arkoma Basin for the purpose of
developing coal bed methane reserves there. The Arkoma Basin, particularly
the Oklahoma side is underlain by coal reserves generally from about 1,500
feet to 3,500 feet.
The coals themselves are typically 10 to 20 feet thick in various
stringers. But they lie fairly close to the surface and are very economical
to drill.
The concern was actually early on was fairly similar to the one that was in
the Powder River that there just wasn't enough gas in place to make the
play economical. However, a number of smaller companies took on the task of
trying to develop this play, and to date, more than 100 coal bed wells have
been drilled by very small, non-public companies. And the results of them
have been pretty good. And we started to watch the play about a year ago,
started to take some non-operating interest in these wells and learned how
these operators were drilling them.
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We then began to get very aggressive on the land side. A big diversified
natural gas company came to us that was also eyeing the same play,
recognized our head start on the land side and so we formed what was
initially a 75/25 JV where they basically paid all of the up-front costs in
exchange for 75% of our acreage. But we have the right in the next couple
of months to adjust the ownership to 33/67 which I believe we'll probably
do.
The advantages to the play are simply that the wells can be drilled quickly
-- 15 to 30 days. We complete them and we put them on-line. The low
pressure gathering systems are already in place. There's no need to dewater
these coals. And so the return on investment in our view is much better
than the Powder River; plus we are selling gas at only a 15 - 10 to 15 cent
discount to NYMEX rather than 75 cent differential that you see up in the
Powder River, so the disadvantage is that even as a first mover, we can't
go in and lay in an acreage position of hundreds of thousands of acres.
Most of the land is HBP. It's very chopped up. It's hard to get a toehold
position. But we and our partner are now moving in on close to 100,000
acres of land. And this is what we excel in.
We excel in putting together big land positions in difficult basins. And
the Arkoma has been a place where we've operated for 15 years and so we
have some advantages there.
So all this is to say, we like the play very much. We will attack it
conservatively at first and then based on the results, go forward from
there. We have a big inventory of acreage and this is I think a
demonstration of some of things that we do best - going into these areas
and carving out a big land position for ourself.
Tom Parker: And so your expectation you wouldn't see a fair amount of drilling
until next year or even - is it beyond that?
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Aubrey McClendon: Our initial program this year will actually start in the third
quarter, the quarter that we're in now. And we've budgeted to drill about
20 wells during the remainder of this year and we could go up on that by a
large number next year. Right now, our tentative budget calls for 40 wells.
We're not asking anybody to model a production growth number in on this.
This is again a play that while other companies think they've proven, we
haven't proven it to ourselves yet. But it could be an area that becomes
very important to us in 2001.
Tom Parker: Okay, thanks.
Operator: Shawn Reynolds, Goldman Sachs.
Shawn Reynolds: Yeah, real quick. Of next year's production of 140 plus the 30
from Gothic, what portion of that is going to be natural gas?
Aubrey McClendon: When you combine them together, we will be about 88% natural
gas.
Shawn Reynolds: And what's your kind of working outlook with regards to pricing,
commodity prices say 2001 into 2002? Are you running the strip on your
model or are you trying to be more conservative?
Marc Rowland: We haven't been running the strip, because the strip changes too
frequently. We've generally been thinking of a gas price and running
sensitivities between $3.00 and $3.50 MMCF. And that would be NYMEX.
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So our actual official budget that we have right in front of us today is a
$3.50 average NYMEX for the year. But we've stress-tested it, Shawn, down
to $3 and, you know, even lower numbers. It's just a function of how much
discretionary cash flow is generated above a capital expenditure budget
that's projected to be around $170 million pro forma for the Gothic
acquisition in 2001.
Aubrey McClendon: For the record, we also budget for $24.50 on NYMEX loss.
Shawn Reynolds: Right, and I think I missed it. What's the pro forma for Gothic
going to be? You talked about your coverage ratio. What about your debt to
cap ratio?
Marc Rowland: Debt-to-book-cap?
Shawn Reynolds: Yes.
Marc Rowland: Debt-to-book-cap won't - is sort of unknowable, because the
biggest issue we have is a potential positive adjustment for re-booking the
deferred tax assets that we previously took a valuation allowance on.
If we looked at not booking that with the equity issuance we have, we're
projecting to be roughly at zero common shareholder book equity, including
retained earnings, as of the date of the acquisition. If we do book it,
then you'd have $400 million potentially in restored book equity on a
common basis.
We think more in terms of - a more useful measure is debt per MCF
equivalent. We started the year with $1 per MCF in total fixed obligations,
basically 1.2 BCF against 1.2 fixed obligations - millions of dollars -
billions of dollars.
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We're looking for that, as explained earlier, to be post to the transaction
between $1.1 and $1.2 billion essentially unchanged, or perhaps even
slightly down from last year at the beginning of the year, and reserves of
$1.6 to $1.7 billion.
So we're shooting ultimately to get the debt per MCF number down on our
asset base to around 60 cents an MMCF. We see this transaction and the
other equity-related issuances that we've talked about, including the
conversion of the preferred, taking it to between 65 and perhaps 70 cents
an MMCF, down significantly, but still not to our target level.
Shawn Reynolds: Given that, don't - I mean, wouldn't you want to be maybe a
little bit more aggressive on reducing your debt? I mean, that kind of gets
you back to a situation where if we have a downturn, you know, this time
next year, and say we're looking at $2.50 again on the gas, that might
start to be problematic for you.
Marc Rowland: If gas goes to $2.50, which is, you know, where it was two years
ago, you know, we have adequate cash flow to do our capital expenditure
budget and maintain our fixed obligations. We won't grow very much at that
level, like no one else in the industry will.
But again, our desire is to put in a - ultimately a bank-type facility to
replace the Gothic senior notes, whether we have to wait for first call or
not, and to have that portion of the capital structure be able to be repaid
down with excess cash flow.
And so yes, it is our intent to continue to de-lever, but also to de-lever
on a relative basis. We're still in the business to grow and if we can add
reserves that are attractive, stress-tests to $2.25 or $2.50, and grow the
left side of the balance sheet, keeping the right side flat, we're
de-levering at that as well.
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Aubrey McClendon: Shawn, in my view our alternatives are, we can just reduce the
debt with what we have and keep assets where they are, or we can grow the
asset base and de-lever relatively. And that's the path that we've chosen,
because the return from investing our cash today in additional assets at
today's acquisition costs. I mean, we can imagine an environment where
acquisition costs or drill bit costs are such that it's not a better use of
our cash to grow the left-hand side of the balance sheet, so I think you
have to ask that question and hear the answer in the context of what our
return on investments can be at today's prices. So I think you'll see us
kind of continue to de-lever relatively, and debt per MCFE go down as a
result of it.
Marc Rowland: I would point-out further that you have - as evidenced by this
quarter's $35 million of capital expenditures for all drilling activities,
that you've not seen any increase at all in the company's effort to ramp-up
drilling.
We are very mindful of the excess cash flow that can be created. We did use
it for attractive acquisitions. The first six months our acquisition costs
were well under $1 per MCFE. And so we feel like those opportunities are
significantly better than incremental drilling opportunities that we were
faced with on any significant dollar level.
Shawn Reynolds: It just seems like you guys have come so far from where you
were. I'd just hate to see you get back into a situation where, you know,
you got stuck again.
Aubrey McClendon: No one would hate it worse than us.
Shawn Reynolds: Yes, I hear you.
Aubrey McClendon: We don't intend to let it happen.
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Shawn Reynolds: Okay. All right. We'll leave it at that.
Aubrey McClendon: Hey, Shawn, it's good to hear from you.
Shawn Reynolds: Yes.
Operator: The next question comes from Doug Adams, Davenport & Company.
Doug Adams: I have a question on the PV-10 value. Is that computed as an
after-tax number?
Marc Rowland: That is not. The SEC calculation does not have an income tax
provision in it. However, our income tax rate would not be very significant
in that calculation.
Doug Adams: Right. Thank you very much.
Operator: Barry Sahgal, Brean Murray & Company.
Barry Sahgal: Hi Aubrey.
Barry Sahgal: I guess most of my questions have been answered. But perhaps you
could elaborate a little on your philosophy towards hedging right now.
Aubrey McClendon: That's probably the most difficult question Barry, as you
know. And as we've talked about in the past, because the curve has moved
around so much over the past couple of months even.
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So right now I mean, if we had been given the opportunity to hedge out for
a couple of years at no cost, at $4.50, we would have taken advantage of
that. But while the front months got that high, you know, the back months
really didn't, plus there are significant costs associated with hedging,
and we took advantage of several trades where we could overall - where the
effect of which was to raise our existing hedges from around $2.45 to
almost $3.00.
We're pretty comfortable right now sitting where we are, unhedged for the
winter and unhedged for 2001. We believe that this pullback that we've seen
in gas prices is one that probably could have been anticipated, and I think
sets the stage for a real nice run-up in the fall and winter.
You know, right now, even with some slightly stronger injections over the
past month, we're looking at, you know, maybe 2.7 BCF in storage, rather
than 2.5 or 2.6. Some numbers - you know, point to lower than that. I think
it's still uncharted waters and we'll remain unhedged.
If we get some opportunities to hedge some above-$4.00 gas in 2001, and we
feel like we can afford the cost of that and the risk of that, I'm sure
it's something that we'll actually consider. But right now, there's nothing
that we see on the strip out there that's attractive enough to go hedge it
today.
Barry Sahgal: Good enough. Thank you.
Aubrey McClendon: Thank you.
Operator: Andy Parr, Loomis Sayles.
Andy Parr: Morning, guys. I had a question. Do you have any comments on Gothic's
hedging to the end of the year? Do you have any feel for those?
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Aubrey McClendon: Sure.
Marc Rowland: We know exactly what it is. As of yesterday anyway Andy, the
company remains unhedged after October. And through October, approximately
65% of their gas is hedged at a wellhead realization of just under $2.50.
So by the time the merger is complete with Chesapeake, we will be acquiring
unhedged volumes.
Andy Parr: Okay. What kind of agreement do you have with them I guess,
restricting cash -- you know, the use of cash going forward until the
merger is complete?
Aubrey McClendon: Well we have a standard letter agreement in place now pending
the signing of the definitive merger agreement. And it has the usual
provisions on due course of business and, you know, just the standard kind
of merger language with respect to, you know, no unusual expenditures and
so forth.
We're in close contact with both Mike and Steve. And, you know, they're
running their business as the company should be run, in our opinion. And,
you know, we discuss any significant decisions before they occur.
Andy Parr: All right. Thanks.
Operator: Richard Kleinbaum, Chelsea Ventures.
Richard Kleinbaum: Congratulations, Aubrey and Marc, on a great quarter. I have
two questions. Is tight rig availability in any way inhibiting exploration
activities?
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Aubrey McClendon: Okay. Do you want give us your second one? We'll take them
both.
Richard Kleinbaum: All right. And the second one is your projection for natural
gas prices for Q4 and 2001 for gas prices.
Aubrey McClendon: In reverse order, I'd just go back to where we are in terms of
our budgeting process. For 2001 we are budgeting for a $3.50 NYMEX price. I
think for the fourth quarter of this year we're anticipating around $3.75
or so. So we would have hoped to have been higher than that maybe six weeks
ago. But six weeks from now, we might be looking at higher numbers. But
those are - we're not budgeting for anything north of $3.75.
With regard to rig availability, it certainly has tightened up. We think it
has tightened up less in our neck of the woods here in the Mid-Continent
than maybe along the Gulf Coast and in South Texas.
We have seen an increase in drilling rig costs that are pretty significant.
Luckily though, those really haven't translated throughout the cost of the
entire well. And we still feel like our drilling costs are only up 10% to
15% overall.
You can see some evidence of this in our numbers. Our depreciation rate
actually went up a penny this quarter and it wasn't for the drill costs to
date. That was influenced by our anticipated future development costs,
which we went up and increased pretty significantly at June 30 to, we
think, to match where the market is today.
So the - you know, overall, we think our finding costs are going to creep
up some, but the tradeoff is to get $1.00 more at the wellhead, and to pay
maybe 10 cents more to find that gas, and we think it's a good tradeoff.
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The people who are probably most affected by the tight rig market are the
guys who haven't drilled any wells for the last couple of years and now all
of a sudden want a rig.
They have, you know, no relationships with the rig companies, and find it
very hard to pry a rig loose -- companies like Chesapeake, EOG, Anadarko,
Apache -- people who traditionally are large drillers in the Mid-Continent,
we typically get to keep the rigs that we have, and any new rigs that get
freed-up, we typically get first call on them as well.
We're also starting to see some new built rigs come into the market as
well. And some of those are new new built and some of them are coming in
from the weeds, being refurbished and brought into action. And none of our
drill bit activities are being affected negatively by just not being able
to get a rig.
Richard Kleinbaum: Thanks a lot.
Aubrey McClendon: Okay.
Operator: Keith Chan, Alliance Capital.
Keith Chan: Hi. I noticed that in your forecast, most of your costs had gone up
a little bit, 1 or 2 pennies. Can you share with us in terms of what type
of assumptions you've put in those forecasts? I'm talking about in the
press release, starting on the second page, at least my second page, on
LOE, G&A, and DD&A cost increases?
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Aubrey McClendon: Right. The DD&A rate, we did forecast would increase a little
bit as a result of just higher finding costs. G&A has bounced around
between 9 and 10 cents per MCFE. And we think it will stay there.
Lease operating expenses, the actual lifting costs, we're pretty
comfortable that those are going to be between 35 and 40 cents per MCFE. We
will see some quarterly bouncing around as we do workover programs or just
have unusual expenses hit. So I don't think you should get locked in too
much on one number, but work within that range of 35 to 40.
And then production costs are just a function of what the wellhead revenues
are and that's the only part of our cost structure of course, that we
prefer to see go up, you know, over time.
Marc Rowland: I'd point-out that while lifting costs themselves, excluding the
production taxes, are largely fixed, they're not completely fixed. For
example, ad valorem taxes in Kansas and Texas are up as a result of higher
well bore prices. The states evaluate the value of those products based on
current market conditions, and assess taxes accordingly. And so the ad
valorem taxes in Texas can run 2-1/2% to 3% of the revenue stream. And as
the revenue stream doubles, ad valorem taxes go up. And that's an item
that's not in production taxes. That's in lifting costs.
Keith Chan: I see. Thank you.
Operator: Ladies and gentlemen, just a reminder, if you would like to ask a
question, please press star 1 on your touch-tone telephone. Again, star 1
for questions.
We'll go to Steve Schweitzer of Shenkman Capital.
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Steve Schweitzer: Good morning. As I understand it, Gothic will be a subsidiary
of Chesapeake. Is that correct?
Marc Rowland: That is correct.
Steve Schweitzer: Will there be a bank facility at that level?
Marc Rowland: The Gothic notes have carve-outs that allow bank facilities to be
in place. Their current bank facility -- my understanding -- has an
outstanding draw on it of about $15 million. And that's the current level.
We intend to pay that off at the date of the merger, either through Gothic
money or through Chesapeake funds.
Whether or not we'll - I mean, there's not much reason for us to maintain a
bank facility down there based on current expectations of cash flow, versus
post-merger G&A and capital expenditure costs.
Steve Schweitzer: But you could put up to $15 million of debt at that level?
Marc Rowland: Actually that is the bank level - that is the level imposed by the
bank. The indentures allow for more debt to be put on it than that level.
Previously Gothic was at a $25 million bank facility, which fit-in to their
restrictions at the time. As prices go up -- their indentures work similar
to ours and there's greater amount of bank debt that can be put on with
that security ahead of the senior secured notes.
Steve Schweitzer: And at the Chesapeake level, how much senior debt can be put
ahead of the senior notes right now?
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Marc Rowland: At this time, the estimate is based on 1-1 pricing of 2000 which
is the way our indentures work with respect to keeping prices the same all
year.
That level is $150, $160 million. At today's prices, if we were to see
those prices at 12/31/2000, that number would jump up significantly,
perhaps doubling from current levels.
Steve Schweitzer: And how is that determined? That's off of a...
Marc Rowland: It's off of adjusted consolidated net tangible assets. There are
dollar amounts that are fixed under two of our indentures, plus a
percentage of consolidated net tangible assets.
We call that ACNTA or A, C, N, T, A. And that is based on the company's
present value of reserves at pricing dictated by the indentures, which is
the SEC pricing as of the end of the year.
And then it's the amount of those reserves that are evaluated by
independent third party engineers times that formula. Then there's the
current assets, current liabilities, and other assets, which are a minor
part of our calculation.
Steve Schweitzer: Okay. Thanks very much.
Operator: Robert Miller, Boulevard Trust.
Robert Miller: Congratulations, fellows, for a nice quarter. I have two
questions about the coal bed play. How long do the wells that you plan on
drilling there - how long do you plan on their being productive?
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And the second question is, which contractor are you using for that play?
Aubrey McClendon: With regard to contractor, I assume you mean drilling
contractor.
Robert Miller: Yes.
Aubrey McClendon: And we're using a series of small private companies that have
rigs with depth capabilities of 2,500 to 3,500 feet.
With regard to how long the wells will produce, since we don't have any
right now producing, it's hard to know. But based on similar Arkoma Basin
production, we would anticipate well lives of 10 to 20 years.
Robert Miller: Okay. And then are you going to do any horizontal drilling?
Aubrey McClendon: That's a good question. There have been a number of horizontal
wells drilled in the play to date and a number of vertical wells as well.
Right now, we favor the vertical drilling approach to the play.
Robert Miller: Okay. So there's no particular publicly owned contractor that's
got expertise that you feel valuable in that kind of play.
Aubrey McClendon: That's correct.
Robert Miller: Okay. Thanks gents.
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Operator: Gentlemen, that does conclude today's question and answer session. So
at this time, Mr. McClendon, I'll turn the program back over to you for any
additional or closing comments you might have.
Aubrey McClendon: Great. Thank you all very much for your participation. If you
have additional questions, please let us know. We'd be happy to talk with
you further. Thank you. Bye.
Operator: That concludes today's program. There will be a rebroadcast of this
conference available today at 12 o'clock Eastern Time, running through
August 4 at midnight Eastern Time.
To access this rebroadcast, you can simply dial 1-719-457-0820, and use
passcode 638606. Again, thank you all for your participation. You may now
disconnect.
END
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