Filed by Whiting
Petroleum Corporation
pursuant to Rule 425 under the Securities Act of 1933
and deemed
filed pursuant to Rule 14a-12
of the Securities Exchange Act of 1934
Subject Company: Equity
Oil Company
Commission File Number: 000-00610
The following is a transcript of a
conference call held by Whiting Petroleum Corporation on February 25, 2004.
WHITING PETROLEUM
Moderator: Michael
Stevens
February 25, 2004
12:00 pm CT
| Operator: |
Good
afternoon. My name is (Miles) and I will be your conference facilitator today. |
| |
I
would like to welcome everyone to the Whiting Petroleum Corporation fourth quarter and
year-end 2003 earnings conference call. |
| |
All
lines have been placed on mute to prevent any background noise. After the speaker’s
remarks there will be a question and answer period. If you would like to ask a question
simply press star then the number 1 on your telephone keypad. If you would like to
withdraw your question press the pound key. |
| |
I
would now like to turn the call over to Mr. Mike Stevens, the company’s Treasurer.
Sir you may begin. |
Michael
Stevens: |
Thank you. |
| |
Please
be advised that our remarks that follow including answers to your questions include
statements that we believe to be forward-looking statements within the meaning of the
Private Securities Litigation Reform Act. These forward-looking statements are subject to
risks and uncertainties that could cause actual results to be materially different from
those currently anticipated. Those risks include among others matters that we have
described in our earnings release issued today and in our filings with the Securities and
Exchange Commission. We disclaim any obligation to update these forward-looking
statements. |
| |
In
light of the pending acquisition of Equity Oil Company by Whiting Petroleum Corporation I
must inform you that this presentation may be deemed to be solicitation material with
respect to such pending acquisition. In connection with the proposed merger a
registration statement on Form S-4 and other relevant documents will be filed with the
Securities and Exchange Commission. Investors are encouraged to read the registration
statement and any other relevant documents filed with the SEC because they will contain
important information about the proposed transaction. After these documents are filed
with the SEC they will be available free of charge at the SEC’s Web site, www.sec.gov. |
| |
Whiting
and Equity and their respective directors, executive officers, and other employees may be
deemed to be participant in the solicitation of proxies and respect of the proposed
transaction. Information regarding the participants and the proxy solicitation and a
description of their direct and indirect interest by security holdings or otherwise will
be contained in the proxy statement prospectus and other relevant materials to be filed
with the SEC when they become available. |
| |
During
this conference call we will make reference to our finding, development, and acquisition
cost which is a non-GAAP financial measure. A reconciliation of this non-GAAP measure to
the applicable GAAP measure can be found in our earnings release issued today, a copy of
which is located on our Web site at www.whiting.com. |
| |
Now
it’s my pleasure to introduce James J. Volker, Chairman, President and Chief
Executive Officer of Whiting Petroleum Corporation. |
James
Volker: |
Good morning everyone and welcome to Whiting Petroleum’s first conference call for
investors and analysts. It’s my pleasure to recap financial 2003 fiscal and
operating results, discuss recent announcements, and welcome questions from investors and
analysts following our presentation of our highlighted financial and operating results. |
| |
First,
to mention recent announcements Whiting is an acquisition, exploitation, and expiration
and production company. A recent example of a portion of our acquire, exploit, and
explore growth strategy is the pending merger of Equity Oil that we announced on February
2, 2004. We expect this merger to be accretive to our 2004 earnings, cash flows, and
reserves. |
| |
We
ask that you limit your questions about Equity to topics addressed in our February (2000)
news release as the S-4 document that we and Equity will be filing within the next couple
of weeks should be then available on the SEC Web site. |
| |
Also
in February 2004 we announced we had paid down $40 million of debt on our credit
facility. We believe that under our growth plan it’s important to retain financial
flexibility to take advantage of opportunities to expand the company. We also seek to
maintain a reasonable debt to capitalization profile of approximately 35 to 40% and after
the pay down our debt to equity ratio is at the lower end of that range. |
| |
With
respect to capital expenditures during 2003 our capital expenditures totaled $52 million
all funded with cash flow from operations. This number includes acquisitions which
totaled 10.9 million therefore drilling cap ex was approximately 41 million. We used
additional cash flow to reduce debt by 40 million as I previously mentioned. |
| |
We
anticipate our 2004 drilling capital budget will be approximately 68 million which we
expect to be split approximately as follows, 48% or 33 million will go toward the
development of proved undeveloped reserves and 38% or approximately 26 million is
budgeted for the drilling of probable reserves which if successful would be reserve adds,
14% or approximately 9 million will be directed toward possible reserves which if
successful would also be reserve adds, approximately 80% of our drilling budget is
operated and any acquisition opportunities would increase the capital budget. |
| |
With
respect to production and drilling results we produced a company record 37.2 billion
cubic feet of gas equivalent in 2003. Excluding the Equity transaction or any other
acquisition we’re forecasting an approximate 10% increase for 2004 production. We
replaced 170% of our 2003 production at a cost of 86 cents per Mcfe. Over the past four
years our production replacement ratio is 307% and our all sources, finding, development,
and acquisition cost per Mcfe, is $1.15. |
| |
Our
acquisition activity has been brisk in the past four years especially in the period 2000
through 2002. During that four-year period we acquired 371 Bcfe of proved reserves at an
average cost of 93 cents per Mcfe. Whiting has made acquisitions since 1983 in all price
and acquisition environments. We have a track record of successfully meeting our
investment goals for acquisitions regardless of the environment. We expect to continue
making acquisitions. |
| |
I’d
now like to call on (Jim) Casperson, our CFO, to discuss some (unintelligible) and help
you assess our performance. |
James
Casperson: |
Thank you (Jim). |
| |
Good
morning everyone and for you in the East good afternoon. |
| |
Let’s
cover the results for the year ended December 31, 2003. Our financial performance was
indeed strong in many of the key categories that are used to analyze oil and gas
companies. We are pleased to have set a number of company records in these areas. |
| |
First,
the income statement. Oil and gas sales for 2003 were a record 175.7 million, a 43%
increase over 2002. Gas sales increased 35.8 million and oil sales increased 17.2
million. Pricing accounted for 95% of the increases as production increased 5%. Increased
volumes were achieved with capital expenditures of 52 million or only 39% of the average
of 134.7 million of capital expenditures during 2000 through 2002. This is a testament to
the drilling and well work in 2003 when cap ex for acquisitions was reduced at the
request of our former parent company in preparation of the IPO thus indicating an
efficient use of these funds. Our cash flow for the year provided by operating activities
was $96.4 million. |
| |
Now
let me address the fourth quarter. |
| |
During
the fourth quarter 2003 we generated $22.2 million of cash flow from operations and I’ll
briefly (unintelligible) go through that calculation. I’d start with the net loss
for the quarter for 316,000, subtract a negative deferred tax provision of (one million
five eight four) add back DD&A of (10 million five eighty-two), a phantom equity
charge of 10,914,000 and a non-cash interest charge of 451,000, add back expiration cost
of 2,171,000 for a cash flow of 22,218,000. To get to (unintelligible) add back the cash
tax provision of 1,738,000, the cash interest of 1,617,000 and subtract interest income
of 151,000 for an (unintelligible) of 25,423,000, take away the expiration of 2,171,000
for an EBITDA number of 22,252,000. |
| |
Now
during that same period of time we had oil production in the fourth quarter of 664,000
barrels, gas production of 5,512,000 Mcfs and prices realized on those products of $27.98
for oil and $4.14 for gas. |
| |
Now
as we go forward it’s worth mentioning that in 2003 our lease operating expense rose
25% to $1.16 per Mcfe. This increase was caused by a higher concentration of operations
in Michigan and North Dakota where historical operating costs are higher and we spent
additional funds on properties acquired in 2002 in these two areas to bring these
operations to Whiting standards. Our DD&A cost in 2003 was $1.11 per Mcfe, a 10%
decrease from 2002. Why? Higher commodity prices and a growing reserve base and longer
economic production life were primarily responsible for this decrease. |
| |
Our
net income, Whiting posted net income for 2003 of 18.3 million or 98 cents per share. The
increase in net income from 2002 of 10.6 million was due to higher commodity prices and
increased production. |
| |
In
addition during 2003 we incurred a one-time 6.7 million after tax charge to earnings for
the phantom equity plan — payment made by our former parent company and a one-time
$3.9 million after tax charge for the implementation of FASB 143. Thus, our earnings were
very good in spite of the aforementioned charges and in the fourth quarter this year we
reported a loss of $316,000. This would have been a $6.4 million profit without this
phantom equity plan charge. |
| |
Let
me summarize the guidance for 2004. As been previously mentioned we expect a production
increase of approximately 10%. We expect our lease operating expense to be in the range
from $1.08 to $1.12 per Mcfe. We expect our general and administrative charge for 2004 to
be between 36 cents and 39 cents per Mcfe and we do not expect to pay any current tax for
2004. |
| |
Let
me go forward to our hedging. We generally limit our aggregate hedging position to less
than 60% of expected production. Currently we have 850,000 Mcfs per month of gas under
(unintelligible) contracts to the end of March 2004 with a floor of $4.50 to ceilings
ranging from $7.00 to $8.45. On the oil side we have 100,000 barrels per month hedged
with (unintelligible) for the first quarter with floors of $28.00 and ceilings ranging
from $31.43 to $32.10. For the second quarter we have a 50,000 barrel per month
(unintelligible) with a floor of $28.00 and a ceiling of $35.40. |
| |
Let
us proceed to the balance sheet. Total assets reached a company record of 536.3 million.
Shareholder’s equity was 259.6 million as of December 31, 2003 compared to 122.8
million at December 31, 2002. Working capital at year end 2003 was 51.3 million compared
to the 19.4 million at December 31, 2002. All proceeds from our IPO went to our former
parent company thus our increase in working capital was generating from our operations. |
| |
Long-term
debt at December 31, 2003 was 188 million but we have reduced this by 40 million because
of our February 17 payment. Our year end long-term debt as a percentage of capitalization
was 42% however net of our cash position this declines to 34%. Our current borrowing base
under our credit facility is $210 million with a $145 million balance today. As (Jim)
pointed out earlier the debt reduction was made possible from cash flow generated in
2003. |
James
Volker: |
Thank you (Jim). |
| |
I’d
like to recap in closing a few key points. |
| |
Whiting
is a growth story. We have a strong balance sheet. We expect to use cash flow to pay for
our 2004 budget. We have flexibility to take advantage of new acquisition opportunities.
We expect our 2004 drilling capital expenditure budget of 68 million will cause
production growth of approximately 10%. Any acquisition we make will add to that growth. |
| |
We
will be participating as a presenting company at the Raymond James 25th Annual
Institutional Investors Conference on March 3, the AG Edwards Energy Conference in Boston
on March 25, the IPAA Oil and Gas Conference in New York from April 19 to the 21 and
(Intercom’s) 9th Oil and Gas Conference in Denver August 1 through the 5. So I hope
to get a chance to meet with you and tell you more about Whiting at those meetings. |
| |
Thank
you for your interest in Whiting and we look forward to seeing you in the near future. |
| |
Operator
I’d now like to turn the call over for questions. |
| |
At
this time I would like to remind everyone in order to ask a question please press star
then the number 1 on your telephone keypad and we’ll pause for just a moment to
compile the Q&A roster. |
| |
Your
first question comes from Greg McMichael of AG Edwards. |
Greg
McMichael: |
Good
morning (Jim). |
James
Volker: |
Morning
Greg. |
Greg
McMichael: |
Just first of all I want to ask you — first of all I want to say congratulations on
being public and also on having a great year — good finding cost and a good quarter. |
James
Volker: |
Thank you Greg. |
Greg
McMichael: |
Second of all I wanted to ask you about the market for acquisitions right now. Obviously
that’s a big part of your growth and I know you’re constantly reviewing
properties in the market. Can you tell us whether the acquisition market has changed let’s
say in the last 90 — 60 and 90 days since you went public and what are you seeing
out there in terms of something that would fit in Whiting’s current existing asset
base? |
James
Volker: |
Greg the acquisition market at this point in time is surprisingly active. We at any point
in time probably have four or five properties under evaluation and at the point that we
believe we will be making offers. |
| |
With
respect to how it may have changed in the last 60 to 90 days really we don’t see
that much of a change over that period of time. It has been active as some potential
sellers choose to take advantage of the current pricing environment. And second we
believe that it is competitive as it always has been however our approach to acquisitions
has always been that if you’re disciplined, if you stick to your knitting, stick to
places that you know, and stick to your essentially rate of return criteria which for us
is typically pre-tax rates of return at typical hedge price (decks) over two to five
years in the 15 to — percent or greater pre-tax rates of return, why that you can do
it. ROE just has to be disciplined. |
Greg
McMichael: |
(Jim) Casperson I wanted to ask you a couple questions about the balance sheet. Long-term
payable to (Aliant) and then other long-term liabilities, could you give us a little more
detail on that? |
James
Casperson: |
Okay. When you’re looking at the long-term liability due to (Aliant) that is
comprised of an amount due to them applicable to the tax sharing arrangement that was
signed in November and was invoked at the time of the IPO. In addition with that there
was a $3 million note to (Aliant) that was signed in that step-up in basis tax sharing
arrangement. |
| |
Now
the other long-term liabilities in there are applicable to the plugging and abandon
liability for the implementation FASB and the long-term portion of the production
participation plan. |
Greg
McMichael: |
Okay and as far as the payable to (Aliant) is that — that’s a tax — it
sounds like it’s primarily income taxes. How will that be amortized? How will you
reduce that off the balance sheet and what’s the schedule of payment there? |
James
Casperson: |
Well the schedule of payment Greg is the tax sharing agreement is ten years long and we
will pay (Aliant) as we (unintelligible) the benefit of any tax saving from the step up
in basis. So when you’re talking about how it gets reduced over a period of time
will be reduced four payments. This is an estimate. At the conclusion of that ten-year
period we will then pay (Aliant) whatever benefit still remains at that point. We do not
expect at this point to make any payments to (Aliant) for approximately 24 months. |
Greg
McMichael: |
Okay
and will there be any imputed interest associated with that? |
James
Casperson: |
Yes
sir there will be. The imputed interest is at approximately 8% and it will accrue
interest at approximately $2.4 million a month - I mean a year as a
non-cash charge. |
Greg
McMichael: |
Okay.
I want to go back to (Jim) Volker for a minute. |
| |
(Jim)
in
terms of the outlook for drilling — you outlined that earlier for 2004.
Where do you see most of the dollars going in terms of the probable
and possible drilling — the 26 million, the 9 million, which I
guess is about 35 million. Is that predominantly in the Williston
Basin or is it balanced between the Williston and South Texas? Are
there other areas there? Could you just outline that for us? |
James
Volker: |
Greg I’ll answer your question by trying to be specific about where the dollars of
the 68 million are going. And I’ll simply say that the probable and possible
drilling is pretty much spread as a percentage in line with the overall percentage as
most of that drilling is simply drilling one location away — currently anyway from
the existing producing well. |
| |
So
with that as background let me say that of the 68 million it would be divided up
approximately as follows – in the Gulf Coast 38 million, Michigan 10 million, the
Rocky Mountains 14 million, the Mid-Continent 1 million, and other, which typically is
non-op drilling that comes in over the year, approximately 5 million. So that totals 68
million. And as a percentage, that’s roughly 56% in the Gulf Coast, 15% in Michigan,
21% in the Rockies, about 1% in the Mid-Continent, and 7% other. And the probables and
possibles are essentially spread in that same manner. |
Greg
McMichael: |
Okay. Thank you. And then lastly I just wanted to get a sense for what your thinking is
on hedging for oil going forward now with oil prices in the 35 to $36 range. Do you think
that the company will be layering on some additional collars in 2004 or perhaps in 2005? |
James
Volker: |
Absolutely with respect to the second half of 2004. And again we’ll be using some
collars and taking advantage of the currently relatively high – historically anyway
– oil prices. In general our philosophy on hedging is sort of like the Hippocratic
oath. We try to do no harm, try to get pretty high floors and even higher ceilings.
Thanks, Greg. |
Greg
McMichael: |
Okay,
thank you. |
James
Volker: |
And
thank you for your assistance out of A.G. Edwards and all of the participants who helped
Whiting go public. |
| Operator: |
Your
next question comes from Tom Nowak of Merrill Lynch. |
Tom
Nowak: |
Hi.
Greg asked most of them, but I was wondering if you could elaborate on the $2.2 million
exploration expense in the quarter. |
| Man: |
During
the quarter we had a couple of dry holes. There were exploratory type wells. Under
successful efforts method of accounting those wells that are not
considered developmental wells are expensed. |
Tom
Nowak: |
Right.
I was - sort of regional what was going on? |
| Man: |
That
would be the offshore Louisiana, our non-operated interest there, and in Montana. |
James
Volker: |
That
was our (Tooksdorf) prospect, which essentially was part of a exploratory play looking at
some Red River bumps. |
| Man: |
Right.
And even though those dry holes were basically determined after year end, we went ahead
and took those as dry holes for the year ended 2003, and then the
remainder of the cost showed up in the fourth quarter with the
ongoing delay rentals as well as any seismic charges and G&G costs. |
James
Volker: |
Mr. (Nowack), we owned roughly 50 to 60% of those dry hole costs and had other companies
participated with us and I guess we’d say the good news about the dry holes is that
at least other people liked them as well as we did, elected to participate with us and,
as part of the transaction, reimbursed us entirely for our front end cost of the acreage
and the leases. So basically we got hit with only our share of the drilling costs. |
Tom
Nowak: |
Great.
That's great. You answered it. Thanks very much. |
| Operator: |
Your
next question comes from Larry Busnardo of Petrie Parkman. |
Larry
Busnardo: |
Good
morning. |
James
Volker: |
Good
morning, Larry. |
Larry
Busnardo: |
How
are you? |
James
Volker: |
We're
great. Thank you. |
Larry
Busnardo: |
Good.
A question just in regards to your capital spending - it's going to be well within cash
flow in '04. Could you potentially increase the capital spending as
the year goes on, or are you purposely under spending cash flow
just in case acquisitions come up or things along those lines? |
James
Volker: |
Good question, Larry. To try to answer your question I’ll tell you how we’ve
loaded our CAPEX currently for the year 2004. But to specifically answer your question,
yes, we could increase it. Our CAPEX is essentially scheduled about 18% in the first
quarter, around 27% in the second quarter, 34% in the third quarter, and 21% in the
fourth quarter. So in round numbers 45% in the first half of the year and, yes, if, for
example, some of the higher potential rate of return drilling that we’re doing in
the first half of the year is successful, yes, we could follow-up then for the end of the
year with an offset. |
Larry
Busnardo: |
Okay. Then just in regards to your guidance – I had it a little bit higher, closer
on the production growth of 15% — was there anything specific that now makes it 10%,
or was it more of a range of say 10 to 15%? |
James
Volker: |
Specifically I’m going to say the 10% number comes from a look at our reserve base
as we look at our CAPEX budget. And I’m going to say you can sort of get there by
seeing that last year comparing CAPEX, even including a little bit of the loop of small
acquisitions that we did last year, this year would be about a 30% increase. So that
would take you from roughly last year’s 5% increase up to about 7%. |
| |
And
then, as I mentioned with respect to just looking at the reserve analysis that we have on
our drilling, even risking it, we get up to about 10% as a result of the potential of the
wells that we’re drilling this year as opposed to last year. As you can tell from
our breakout between puds, probables, and possibles, we’re spending a little bit
more on higher risk drilling this year, roughly 52% as compared to 48% on puds. So the
upper end of the range is definitely achievable, if we do get some success early in the
year on some of our higher risk and higher potential drilling. |
Larry
Busnardo: |
Okay.
And then lastly, would you have the F&D costs on a drill bit only basis? |
James
Volker: |
Yes, it’d be about $1.25 on the drill bit only basis. I’d like to comment on
that, however, Larry, in the sense that with respect to us the number of the reserve
revisions that we received were attributable to our big stick area in North Dakota. That
field essentially, as a result I’m going to say of the team of people that we have
here at Whiting both here in Denver and in our North Dakota office where we benefit from
having the experience of some people who’ve lived with that field when they were
with Exxon. |
| |
And
I’m going to say just were limited as a result of reduced CAPEX budget in that field
– we’ve taken advantage there of a number of work over opportunities and well
work things that we did up there to actually reduce the rate of decline in that field and
increase the rate of reduction as a result of non true drilling activity that we’ve
done up there. |
| |
So,
for example, when we look at the decline rate, where it would have been when we took over
from Exxon, the field would have been down to approximately 1500 barrels a day whereas
today it’s up at about 2,000 barrels a day. So a good share of the reserve revisions
that we’ve enjoyed, as opposed to answering your question about just the drill bit,
are a result of well work CAPEX that we did conduct in that area. Thank you. |
Larry
Busnardo: |
Thank you. And I guess while we're on that, can you give us a breakdown on what
the reserve adds were broken out between acquisitions, extensions,
and the revisions for the year? |
Michael
Stevens: |
This is Mike Stevens. The acquisition reserve growth was 8.9 Bcf. Development
reserves are 31 Bcf. And the revisions were about 23.2 Bcf
equivalent. |
Larry
Busnardo: |
Any sales in that? |
James
Volker: |
Property sales? |
Michael
Stevens: |
No
sales. |
Larry
Busnardo: |
Okay.
Hey thanks a lot. |
James
Volker: |
Great.
Thank you, Larry. |
| Operator: |
Your
next question comes from Jack Aydin of McDonald Investments. |
Jack
Aydin: |
Three questions – one on the – where are you drilling the key wells that you’re
drilling? Second question is are you doing anything in the Cherokee Basin? And the third
question is of the reserve revision prices that account to any of those reserve divisions
higher commodity prices and what percentage? |
James
Volker: |
Okay, Jack. With respect to our key areas, of course, we’re, I should say, most
pleased with the activity that we did along the Gulf Coast in the Stuart City Reef Trend,
i.e., the (Edwards lime) down there, and our Big Stick field where, as a result I’m
going to say of our drilling successes, we’re putting more dollars to work. And I’ve
already kind of summarized that in terms of where we’re spending money with respect
to CAPEX in the year ‘04. |
| |
With
respect to the Cherokee Basin, no, we don’t have any current plans to do anything
there except perhaps later in the year based upon a study that we’re doing right
now. So I can’t say it’s in our budget now. But we may be putting in a pilot
program there in the Cherokee Basin, i.e., our coalbed methane project there. |
| |
I
can say that with respect to the Cherokee Basin, when we went in there, we were hoping to
get the absorption evaluations that came in at around 150 standard cubic feet per ton.
They came in more in the range of 90 standard cubic feet per ton to 100 standard cubic
feet per ton. So, as you can see, they’re at about two-thirds of what we were hoping
for. It doesn’t mean that it’s not economic. It doesn’t mean that it still
can’t be developed. But it does mean that we think we ought to put in a pilot and
see how things go prior to the time that we commit what I would call really substantial
CAPEX to that area where we have about 93,000 net acres in an area that’s crossed by
seven interstate pipelines (unintelligible) to mention something good, where the gas
price would be only about a nickel under NYMEX. |
| |
So
it’s a mixed blessing there. And we do know that some people who have had
developments in the area have sold them. We know other people who are in the process of
actively developing the coalbed methane in that area. So I think it’s just a sort of
area-by-area evaluation. I can tell you that we’re even actively evaluating other
properties to acquire in the Cherokee Basin. So we still think it has good opportunity
for us. But you just want to pick the right area to put your capital in. |
| |
And
with respect to the revisions, actually I really believe that very little of that was
attributable to price increases. It’s mostly the result of the well work that was
done and predominantly in the Big Stick field. And again I could say that I really think
we’ve benefited there from the team of people we put together here in our operations
and exploration department here in Denver working closely with our field office there in
the Big Stick field. |
Jack
Aydin: |
Two
more questions, if you don't mind. |
James
Volker: |
Yes,
go ahead, Jack. |
Jack
Aydin: |
One,
if you have any key well that you're drilling? |
| |
And,
second, I assume you saw the press release from Equity. The production was down. Reserve
was down. Do you care to make a comment? |
James
Volker: |
Well we are drilling a number of key wells, but they’re in our core areas that we’ve
previously mentioned, Jack, essentially the Big Stick field and the Stuart City Reef
Trend and the five fields that we have operations going on in down there. I think I can
say that there has been a minor shift, as you could tell, in that we’re really
putting about 56% of our capital into the Gulf Coast currently so we do think that that
will result in some increases in gas production for us. But no real I guess I’d say
single key wells that I’d wish at this time to note for you. |
| |
Second,
with respect to equity, again I’d simply like to compliment the people here at
Whiting who do our evaluations. Everything that they announced I’m going to say, as
a result of the due diligence we did, we were prepared for. And we look still very
positively at the equity acquisition. And in fact, we’re very enthusiastic about
getting to own all of the properties that they own. We believe that with our greater
CAPEX budget available to us, greater financial capability, and greater staff I believe
that we’ll be able to do good things with their properties. But they’ve been
somewhat limited in the past. |
| |
By
the way, we also think that a number of the operating people that we will acquire there
at Equity, if the merger is voted on positively by their shareholders, a number of those
people bring a wealth of information to us about those properties. And just as we did at
Big Stick and in other areas that we’ve acquired in the past, we believe that those
people will be very instrumental in helping us develop those properties. |
Jack
Aydin: |
Is
(unintelligible) the Knife working on those projects? |
James
Volker: |
Yes,
and the Knife and (Doug Lang) have both (unintelligible)... |
Jack
Aydin: |
I
wouldn't let that one pass by. |
James
Volker: |
Thank
you, Jack. |
| Operator: |
Your
next question comes from Richard Friary of Delphi Management. |
Richard
Friary: |
Yeah, I know you’ve already answered a couple questions on this, but in terms of
these properties it looks as though Big Stick and Stuart City are your big ones. I just
want to know what sort of reserves are under those two properties? You know, what’s
your working interest? And who’s the operator on these properties? |
James
Volker: |
We’re the operator of both properties. Our working interest is just in excess of 60%
at Big Stick and roughly along the Stuart City Reef Trend it generally ranged between 92
and 98%. And in terms of the per well reserves down there we’re generally looking
for in the range of around 1/4 million barrels of oil per well when we develop at Big
Stick, up to 400,000 barrels of oil per well just kind of depending upon whether we
happen to hit a sweet spot or not. And along the Stuart City Reef Trend the range would
generally be between 2 and 4 Bcf per well, Richard. |
Richard
Friary: |
All
right. And how many wells do you have there? I'm just kind of wondering about the total
reserve potential? |
James
Volker: |
In round numbers there’s approximately 20 additional wells that we see at this time
and have scheduled over the next 24 months and both at Big Stick and another 20 in round
numbers along the Stuart City Reef Trend. |
Richard
Friary: |
All
right. Thank you. |
James
Volker: |
You're
welcome. Thank you. |
| Operator: |
Your
next question comes from Pas Sadhukhan of Globes Scan. |
Pas
Sadhukhan: |
Yes, I have a couple questions here. You’re looking at the finding cost per 1,000
cubic feet (unintelligible) starting from 2002, 2003, as you have provided. The 2003
number percentage wise is much smaller than the previous year like 2000 through 2002. Why
is that? |
| |
And
my second question is that, you know, looking at some of the documents – I’m
new to your company – it looks like you have some offshore activity. And in fact,
you mentioned the Gulf Coast of Louisiana. Do you plan to grow also in a significant way
in the near-term or medium-term basis? |
James
Volker: |
I'll
answer that part of your question first, sir. No, we do not anticipate going offshore in
a significant way. We're not staffed up here to be a significant
operator in the Gulf Coast. That is offshore. We are, however, a
significant operator onshore in our Gulf Coast Basin. |
| |
Second,
with respect to the first part of your question regarding our finding cost per Mcfe, as
you’ll note, the CAPEX was obviously only about 30% in the year 2003 of what it had
been in the previous three years. And that’s as a result of the fact that our former
parent company asked us essentially to reduce CAPEX in the year 2003 especially for
acquisitions as we prepared for the IPO as, frankly, they I think – and rightfully
so – didn’t want to put a lot of new capital into us as they were preparing to
sell us. |
| |
And
therefore, we had to do two things. I think we had to be very efficient in terms of
finding places to put the drill bit in our primary areas of operation that had the lowest
finding cost and the highest rates of return and directing them, therefore, our somewhat
more limited capital budget in that way. I think that was healthy for us in the sense
that I think it has prepared us to go forward in the year 2004 and continued to develop
in those areas where we saw the best results. |
Pas
Sadhukhan: |
So
it was somewhat unique in 2003. But you do expect, it seems to me, that perhaps similar
results could be there in 2004. |
James
Volker: |
Yes,
with respect to the drill bit. |
Pas
Sadhukhan: |
Thank
you very much. |
| Operator: |
And
your next question comes from Sam Kidston of Blackrock. |
Sam
Kidston: |
Yeah,
hi guys. First, could you just walk me through the accounting on the phantom equity
plan, exactly what's going on there? |
| Man: |
Okay.
The phantom equity plan was a one-time payment to the employees of Whiting. It was paid
in November of 2003. And the accounting basically was under a
formula, Aliant agreeing to pay the employees of Whiting a
percentage of the growth of the company. And that amounted to
$10.9 million on a pre-tax basis. Once that payment was made then
there was no reoccurring charge. There is - and the plan was over and the employees got
their shares. |
| |
Now
the charge for that was comprised of $4.2 million. It was made in the form of cash as a
capital contribution to pay the employees tax withholding for that and 6.7 million of
Whiting stock, both of those contributed by Aliant for the $10.9 million pre-tax charge.
The shares have been distributed to all of the employees of the company. That’s a
one-time charge. And that plan is over. |
Sam
Kidston: |
Okay.
So there will be no ongoing P&L effect for this. |
| Man: |
No,
there will not be. |
Sam
Kidston: |
Okay.
I just wanted to make sure there. |
| |
And
then just in terms of the mix for the CAPEX budget for next year, is there anything in
there just on the mix that would move around the F&D cost versus this year? |
James
Volker: |
No,
I wouldn't say - nothing in there that would on an overall basis have a big upward or a
big downward effect. |
Sam
Kidston: |
Okay.
Thank you very much. |
| Operator: |
Again,
if you would like to ask a question, please press Star then the Number 1 on your
telephone keypad. |
| |
At
this time there are no further questions. Are there closing remarks, sir? |
James
Volker: |
Only in the sense that we’d like to again invite everyone to the conferences where
Whiting will be in attendance. And I’d like to thank all of the underwriters who
participated in the Whiting IPO. And I’d like to thank all of the Whiting employees
who were so instrumental in getting us to the point where we could do a successful IPO.
And we look forward to continuing success as we move the company forward. Thank you all. |
| Operator: |
Ladies
and gentlemen, thank you for participating today. This concludes our Whiting Petroleum
Corporation conference call. You may now all disconnect. |
END