FILED BY KERR-MCGEE CORPORATION
PURSUANT TO RULE 425 UNDER THE
SECURITIES ACT OF 1933 AND DEEMED FILED
PURSUANT TO RULE 14A-12 UNDER THE
SECURITIES EXCHANGE ACT OF 1934
SUBJECT COMPANY: WESTPORT RESOURCES CORP.
SECURITIES ACT FILE NO. 333-114886
The communication filed herewith is a transcript of an earning release
conference call in connection with the merger of Kerr-McGee Corporation and
Westport Resources Corporation.
Date/Time of Call: April 28, 2004 at 10:00 a.m.
RICK BUTERBAUGH:
Thank you Louise, and good morning. With me today is Luke Corbett, chairman
and CEO, Bob Wohleber, senior vice president and chief financial officer, Dave
Hager, senior vice president responsible for exploration and production activity
and Greg Pilcher, senior vice president and general counsel.
Our comments today will contain forward-looking statements. Please note
that actual results or events may differ materially from our expectations or
projections. Information concerning some of the factors and risks that could
cause material differences are identified in the Risk Factors section of the
company's annual report on Form 10-K, prospectus on S-4 and other SEC filings.
In addition, we will be making reference to figures that adjust the GAAP
results for items identified on page 9 of the earnings release under "Other
Information, Net of Income Taxes." This includes the pricing of oil and gas,
general and administrative costs and all factors that impact operating profit
for both oil and gas and chemical or their components which therefore impact net
income. A detailed reconciliation to the GAAP financial measures can be found on
the company's website at www.kerr-mcgee.com and selecting the Investor Relations
and Guidance tabs. It is likely that during the Q&A period that we may make
reference to other non-GAAP numbers. If this occurs, the appropriate
reconciliations to the GAAP numbers will be posted on our website.
By now, you should have received a copy of Kerr-McGee's first-quarter 2004
earnings release. If you have not received a copy of the press release, you can
access it on the company's website at www.kerr-mcgee.com, by selecting
"First-quarter Earnings."
For the first quarter of 2004, Kerr-McGee once again delivered solid
results in line with our expectations. Production volumes were at the upper end
of guidance, unit operating costs remained in line, and our major development
projects continue on or ahead of schedule. We have already achieved success with
our exploratory drilling program at NW Milne Point project in Alaska and
satellite discoveries in the deepwater gulf. And, we have continued to enhance
our leading acreage position in the gulf where we were high bidder on 22 blocks
in the central Gulf of Mexico lease sale, of which 9 blocks have already been
awarded.
Earlier this month, we announced the $3.4 billion merger of Kerr-McGee and
Westport Resources. This transaction brings high-quality, long-life, U.S.
natural gas assets, primarily in the Rockies, which complement Kerr-McGee's
existing position onshore and in the Gulf of Mexico while maintaining our
historic high-margin cash flow per barrel. As a result, we expect free cash flow
from these properties, after dividends, to add more than $150 million annually.
The Westport properties will significantly enhance our base production and
reserves position. These properties also offer a large inventory of low-risk
exploitation projects where we can apply our tight-gas expertise which was
proven at the Wattenberg field. We believe that these properties will further
enhance the consistency and predictability of both our production and drilling
results as we continue to pursue attractive opportunities in our high-potential
deepwater program.
We are very excited about the opportunities and flexibility that this
transaction provides Kerr-McGee. The transaction is expected to close during the
third quarter of this year, and, therefore, all results and projections
presented today will be for Kerr-McGee only on a stand-alone basis.
For the first quarter of 2004, Kerr-McGee reported net income of $152.2
million. To put this on a comparable basis to Thomson Financial's FirstCall
estimates, excluding special items, foreign currency translation, derivatives
and stock revaluation totaling a $7.2 million charge, as detailed on page 9 of
the earnings release, under "Other Information, Net of Income Taxes,"
Kerr-McGee's adjusted income from continuing operations was $159.4 million, or
$1.48 per share, exceeding the FirstCall consensus estimates of $1.34.
Total first-quarter production averaged more than 270,000 barrels of oil
equivalent per day, once again in the upper band of our expected range. Our oil
and gas volumes both increased from the fourth quarter despite the fact that we
have now excluded previously projected volumes which were associated with
royalty relief fields in the deepwater Gulf of Mexico which are now excluded
from our reported volumes.
The Mineral Management Service has advised that the price thresholds for
2004 are likely to be exceeded and indicated that royalty relief will not be
available on some leases in 2004. Although we disagree with the MMS regarding
the lapsing of royalty relief and are challenging the MMS determination, we have
revised our volume estimates to reflect the MMS position.
The suspension of royalty relief impacts volumes from our Gunnison and
Northwestern fields as well as certain fields in the Nansen/Navajo area. In
total, this is projected to reduce oil volumes by about 1,000 BOPD and gas
volumes by about 15 MMCF per day. Despite this reduction, through efficient
execution and the flexibility of our exploitation program, we have been able to
offset this impact and are still maintaining our original production guidance at
approximately 260,000 barrels of equivalent per day for 2004.
Excluding the royalty relief volumes just discussed, first-quarter average
daily oil production from continuing operations was 143,000 barrels; up more
than 2% from fourth-quarter 2003 volumes and still exceeded our previous
projections. Actual oil sales volumes were 2,300 BOPD greater than reported
production due to the timing of liftings primarily in the North Sea.
First-quarter natural gas sales increased to 763 MMCF per day which is, up
nearly 3% versus the prior quarter. Again gas volume is up despite the reduction
from the royalty relief volumes.
Oil and gas commodity prices continued the upward trend in the first
quarter, increasing from the fourth-quarter levels. Benchmark NYMEX prices for
WTI and Brent averaged $35.25 and $31.30 per barrel, respectively, for the first
quarter. This is up nearly $4.10 per barrel for WTI and up about $2.20 per
barrel for Brent, relative to the fourth-quarter averages. Kerr-McGee's average
worldwide oil prices increased $1.44 per barrel reflecting the impact of our
hedging activities.
For natural gas, the average NYMEX price increased to about $5.70 per MMBtu
for the first quarter, which is up nearly $.30 per MMBtu versus the
fourth-quarter average. Kerr-McGee's average gas realization increased by $1.10
when compared with the fourth quarter, primarily due to higher hedge prices
received in the first quarter.
The combination of increased volumes and pricing resulted in oil and gas
revenues for the first quarter of $752 million, up more than 19% compared with
the prior quarter, as disclosed on page 9 of the earnings release under
"Selected Exploration and Production Information." Marketing revenues of $82
million and associated costs are disclosed separately to give a more transparent
depiction of these activities.
Lease operating expense for the first quarter was $3.58 per barrel of
equivalent, slightly better than our previous projection. The regional breakout
of unit LOE costs for the first quarter is as follows: U.S. Onshore region -
about $2.95; Gulf of Mexico - about $2.80; and the North Sea - about $5.10.
Unit transportation costs in the first quarter were flat with the prior
quarter at $1.08 per barrel of equivalent.
First-quarter unit depreciation and depletion charges for oil and gas
activities were $6.52 per barrel of equivalent and accretion expense associated
with the abandonment provision was $6.6 million. Both of these amounts are
slightly below our previous projections.
Exploration expense for the first quarter was $50.6 million. Just $8.1
million was for dry-hole costs, reflecting the success of our exploration
program to date. On a regional basis, total exploration expense for the first
quarter is as follows: In the U.S. - $32 million; in the North Sea - $12
million; other international - $7 million. Total exploration expense for the
year is still projected to be $300 million, excluding the impact of Westport
activities.
First-quarter drilling success includes the discovery of the Ticonderoga
field located in 5,250 feet of water on Green Canyon Block 768. The well and
side-track deepening encountered more than 250 feet of net high-quality oil pay
from three zones. As a result we have increased our gross expected resource
potential from this satellite field into the range of 30 to 50 million barrels
of equivalent. Additional appraisal drilling will be conducted this year to
fully determine the aerial extent of the field. Kerr-McGee is operator of this
field with a 50% working interest.
Development planning is under way to tie back Ticonderoga to our 100%-owned
Constitution field, which is currently under development just five miles north
of Ticonderoga. Ticonderoga will add significant value to the host Constitution
facility. We are confident we can expand the Constitution facility's oil
processing capacity to about 55,000 barrels of oil per day at minimal cost and
not delay first production from Constitution. This discovery is the most recent
validation of the benefits of our hub and spoke strategy and the reduced risk
profile of our 2004 drilling program.
During the quarter, we also finished drilling the second well at the Dawson
Deep prospect in the greater Gunnison area. This satellite discovery, located on
Garden Banks 625, is being evaluated as a subsea tieback to our Gunnison
facility just three miles away. Kerr-McGee operates Dawson Deep with a 25%
working interest and Gunnison facility with a 50% interest.
The results from Dawson Deep are providing valuable insight into other
satellite prospects around our Gunnison facility. We expect to drill up to two
additional satellites in this area in 2004, all of which we will operate with
50% interests. Later this quarter, we expect to spud the Tin Cup prospect on
Garden Banks 582 which has a resource potential of up to 40 million barrels of
equivalent.
On Alaska's North Slope, we finished drilling two successful wells in the
NW Milne Point area at the Nikaitchuq prospect. The Nikaitchuq #1, a vertical
well, was tested at more than 960 barrels of high-quality oil per day from the
Sag River formation. The #2 well was drilled 9,000 feet southeast of the initial
well and successfully extended the reservoir down dip. We are encouraged by the
results to date and will continue to evaluate the data collected. From this
data, we will re-calibrate our 3-D seismic over this area to better define our
appraisal drilling program for the upcoming drilling season.
You will recall that Kerr-McGee entered this prolific basin in January of
this year where we now hold interests in approximately 18,000 acres and operate
with a 70% interest. We also have an option for an additional 50,000 acres in
this area.
Earlier this month, a well was spud on the San Jacinto prospect in DeSoto
Canyon 618, which we are participating in with a 20% interest. This well is
meeting our expectations and could become part of a future development within
the Atwater Valley area where we already have discoveries at Merganser and
Vortex. On the shelf, a well was spud at Main Pass 113 with Kerr-McGee as the
operator with a 65% working interest. We also expect to spud an appraisal well
at Garden Banks 244 in early May.
Later in the second quarter we expect to spud a deepwater wildcat well in
the gulf at the West Raptor prospect. The West Raptor prospect is located in
DeSoto Canyon 445 and if successful could also be part of the Atwater Valley
development area. The resource estimate for this prospect is 20-40 MM barrels of
equivalent and Kerr-McGee has a 33% working interest.
Two other prospects, Essex and Chilkoot are being prepared for late
second-quarter or early third-quarter spuds. Essex is located in Mississippi
Canyon blocks 23, 24 and 25 and the Chilkoot prospect is located in Green Canyon
320. Again, Kerr-McGee will operate both of these wells with 50% and 33%
interests respectively, which takes advantage of our extensive, recognized
expertise in efficient deepwater drilling. These two prospects offer a total
gross resource potential exceeding 200 million barrels of equivalent.
Internationally, the first of two wells expected in Brazil this year will
spud this week at the Dragon prospect on the BM-C-7 block in the Campos basin.
Kerr-McGee participates with a 33% interest. We estimate the gross resource
potential on this prospect to be 100-400 MM BO.
Moving to our major development projects, each remain on, or slightly ahead
of schedule. At the Gunnison facility, we have now completed the second dry-tree
well and production continues to ramp up. Current rates from the three subsea
wells and two dry-tree completions are more than 12,000 BOPD and 140 MMCF per
day. The remaining five dry-tree completions are expected to be finished by
year-end, resulting in total volume of approximately 30,000 BOPD and 180 MMCF
per day.
The cell spar and topsides for the Red Hawk field have now been completed
and installed. The commissioning phase is ongoing, and the subsea lines have
already been tied in. The export line will be pulled through and hung off this
week. We are still on track for first production about mid-year.
At the Constitution field, first steel has already been cut in Finland for
fabrication of the spar and the topsides in Houma, Louisiana. We are currently
evaluating options to increase topside capacity for the probable tieback of the
Ticonderoga discovery. However, we do not expect this activity to change our
estimate of first production from Constitution which is still expected mid-year
of 2006.
In Bohai Bay, development drilling is in progress with two rigs working,
and construction of the hub FPSO facility is proceeding well.
Looking at the second quarter, we are maintaining our previous production
guidance despite the impact of eliminating volumes associated with royalty
relief that I discussed earlier. Additionally, we still anticipate producing in
the range of 252,000 to 271,000 barrels of equivalent per day on average for the
year. A detailed quarterly breakout of expected production volumes for 2004 by
product and by region is available on the company's website at
www.kerr-mcgee.com by accessing the guidance tab in the investor relations
section.
Unit lease operating costs for the second quarter are projected to increase
to about $3.75/barrel of equivalent, and depreciation and depletion charges are
projected to be $6.90/barrel of equivalent. Exploration expense is expected to
be approximately $75 million.
In our chemical operations, adjusted operating profit for the first quarter
of 2004 was $2.7 million. Adjusted operating profit from just our TiO2 pigment
operations was $5.4 million, at the low end of our previous guidance. This
reflects the projected decrease in sales volume from the fourth quarter
partially offset by a slight improvement in net realizations. We are beginning
to see signs of marginal improvement in both volumes and pricing, however Europe
continues to be volatile with pockets of weakness. Unexpected operating
interruptions at our Hamilton and Botlek plants negatively impacted
first-quarter operating costs but we believe these issues will be fully resolved
in the second quarter. Combined plant utilization rates averaged approximately
90% during the first quarter.
TiO2 capital projects remain on schedule, and commissioning of the
High-Productivity Oxidation Line at the Savannah plant continues. We
successfully began to ramp up production but as expected we will incur higher
start-up costs during this period.
Sales volumes are expected to rise with the seasonality during the second
quarter and as a result, we expect second-quarter operating profit from all of
our chemical operations to increase into the range of $8-$10 million.
The corporate portion of adjusted G&A cost as well as other costs was about
$31 million on a pre-tax basis in the first quarter. Net interest expense for
the quarter was about $56 million.
At this time I will turn the call over to Bob Wohleber, who will review the
other financial items. Bob....
BOB WOHLEBER:
Operating profit during the quarter increased to $330 million, which is a
58% increase over the $209 million operating profit generated last quarter. Net
Income for the quarter increased to $152 million, which is a three-fold increase
over the reported fourth quarter income number of $50 million.
During the first quarter, the company generated $493 million of operating
cash flow before considering changes in working capital. The working capital
change represented a $218 million use of cash, which relates primarily to a
reduction in accounts payable and accrued liabilities.
Debt at the end of the first quarter was $3.482 billion versus $3.656
billion at December 31, 2003, a reduction of approximately $174 million.
Approximately $100 million of the debt reduction was paid down from cash
generated from operations and the balance represents the removal of the
short-term lease associated with the Gunnison project, which has now been
refinanced as an operating lease. At quarter-end, the company had paid off all
of its bank revolver and commercial paper, and we finished with a cash position
of over $143 million.
We continue to make solid progress in reducing debt and we expect
additional debt reductions throughout the balance of the year.
In summary, Kerr-McGee has posted solid results in the first quarter with
net income of $152 million and operating profit of $330 million. We are pleased
with these results and will continue to work our strategy to add value for our
shareholders.
At this time I will turn the call over to Luke Corbett.
LUKE CORBETT:
Thank you Bob and good morning. As you have just heard from Rick and Bob,
we once again reported solid operating and financial results. We have met our
targets while remaining focused on controlling costs and exercised financial
discipline to further delever our balance sheet. I am confident that we will
continue these achievements in the second quarter.
Now, as you are likely aware, the boards of Kerr-McGee and Westport have
unanimously agreed to merge the two companies in a stock for stock exchange. We
are extremely excited about this combination and the numerous benefits that we
believe it brings to Kerr-McGee and our shareholders. The Westport assets
complement our existing U.S. core areas with quality natural gas assets. In
addition, these assets expand our base of low-risk exploitation projects in
areas where we have a proven track record of success. By underpinning this
transaction with attractive hedges we expect to generate more than $150 million
of additional free cash flow next year which can be used to accelerate drilling
activity or further reduce leverage. We have already begun the planning to
integrate these assets into our portfolio to maximize their value. The bottom
line is this transaction brings depth, breadth and balance to our E&P Program
providing us with a more predictable performance profile. So we truly believe
that this transaction is a win-win for both Kerr-McGee and Westport
shareholders.
At this time we would be happy to answer your questions.
LOUISE:
Thank you. Ladies and gentlemen, if you wish to ask a question, please press
star followed by one on your touch tone telephone. If your question has been
answered or you wish to withdraw your question, press star followed by two.
Again, that is star one to ask a question.
And your first question comes from David Connie from Freidman, Billings, Ramby.
Please proceed, sir.
DAVID CONNIE:
Yeah, hi, guys. This is actually a question for Dave on Alaska. Was the second
well, was that a horizontal well? Could you refresh my memory there?
DAVID HAGER:
No, it was not. It was just a directional well, it was not a horizontal well. It
was just a well to test the down depth limits that we found sand -- base.
DAVID CONNIE:
Okay. And what is the biggest challenge, do you think, in Alaska?
DAVID HAGER:
Well, I would say that overall, there's no question that we have found oil over
a large aerial extent. I think what we have to prove up yet that we can get
individual rates from each well that makes it an economic discovery.
So we're eventually going to have to go out there next year after we -- we're
recalibrating our seismic and we'll go out during the next drilling campaign and
drill some additional wells. There's a large resource there that we're pretty
confident, but you have to make sure the economics on an individual wells and
support facilities, make sure it's an overall economic project. So I would say
rates are the big issue that remain to be determined. We're optimistic after the
rate we got from the vertical well. We eventually plan to develop a horizontal
well, so we eventually need to get a horizontal well test out there.
DAVID CONNIE:
Would the third well be potentially be horizontal?
DAVID HAGER:
Potentially. We haven't finalized that at this point, David. We're looking at
that. We're looking at whether we want to go with one rig or two rigs next year
depending on the number of wells we want to drill, so that's what the team is
working through right now is to finalize what the plan would be for the next
drilling campaign. But I would say most likely it will include a horizontal
well.
DAVID CONNIE:
Okay. And then on the Brazil wells, you are going to spud the first one this
week or so. How long does it take to hit TD and when do you think we'll hear
some results?
DAVID HAGER:
It will probably take on the order of 30 days or so to hit TD, so we'll announce
results soon after that.
DAVID CONNIE:
Okay. And then would you go and would the second well spud thereafter?
DAVID HAGER:
Do you mean the second well on that same prospect? Let me just answer the
question there. We won't necessarily immediately drill a second well on that
prospect. It will depend on the results of the first well. Now, we do have
another block in Brazil, the BMES-9 block where we will be drilling an
exploration well, we'll spud it here in the second quarter as well.
DAVID CONNIE:
Okay. So they will be running parallel to each other, so to speak?
DAVID HAGER:
Yeah. We may be finished with the first one by the time we spud the well on the
BMES-9 block.
DAVID CONNIE:
Okay. Great. Thanks a lot, guys.
LOUISE:
And your next question comes from Jim Margar from Rainer Investment Management.
Please proceed, sir.
JIM MARGAR:
Hi. Could you discuss a little bit what you have done with regard to hedging
activities excluding Westport over the last quarter and where you stand in the
hedgings for this year and next year?
BOB WOHLEBER:
Sure. Yeah, this is Bob Wohleber.The hedging that Kerr-McGee has done is we've
outlined it on our web page so you can access it there for each of the quarters
for our oil and gas. For the -- for crude oil in the second quarter, we have 106
barrels basically hedged 54,000 WTI at a $28.23 price, 51,800 barrels a day
Brent at 26.23. And then our gas, 565,000 and then BTUs per day at $4.74. The
remaining hedges, again, are outlined on our web page. You can access that
information. We have not done any Kerr-McGee hedges in '05 other than the hedges
associated we've done in contemplation of the Westport transaction.
JIM MARGAR:
What do you anticipate doing with regard to '05, do you have any clear plan on
that yet or are you going to kind of take it as it goes?
BOB WOHLEBER:
Yeah, I mean, what we do with that is we look at this as we contemplate our cash
flow needs, the price environment. We take those recommendations to our board
and make a determination. At this point we do not have any recommendation for
'05 at this juncture.
JIM MARGAR:
Thank you.
BOB WOHLEBER:
You bet.
LOUISE:
And your next question comes from Brad Loofer from Bare Sands. Please proceed.
BRAD LOOFER:
Good morning. I have three questions. First, Rick, the exploration expense came
in about 10 million below your guidance, but you haven't changed the guidance
for the year. So should I just assume that these were timing issues or what's at
work there?
RICK BUTERBAUGH:
Well, that's -- really shows the success of the program in the first quarter.
Now, the way we budget our program, because we are a successful efforts company,
we budget both our capital program and our exploration program separately. We've
maintained the budget of 300 million for exploration expense and with the
success of the wells to date, it gives us additional opportunities to bring
additional wells into the program throughout the year.
BRAD LOOFER:
I see. Okay. We shouldn't read it that you are probably going to come in lower
on the exploration expense then?
BOB WOHLEBER:
No.
BRAD LOOFER:
Secondly, you didn't mention anything about Yorktown. What's going on there?
UNIDENTIFIED SPEAKER:
Well, on Yorktown, Devon has stepped out of the prospect and so we have that at
100 percent interest. We have completed our cost estimates for going back out
and completing the well and we still feel very much that there's a viable
prospect. The regional data indicates that there is -- we may be potentially
drilling into the most sandy interval in the middle myoseen (phonetic) objective
section there that we haven't drilled that yet. So we have completed our -- much
frankly, we'd like to bring a partner in on that, so we're showing it to
potential interested parties on the street. Given the timing of that, and that
we're now entering the season where loop currents could occur, we don't plan to
go out there where there's any risk of that occurring again this year, so I
would say it's most likely that if we drill this well, it won't be till late
third quarter, fourth quarter, something like that.
BRAD LOOFER:
And how do you treat the expenses to date? At this point I imagine they are just
-- it's a suspended well, right?
UNIDENTIFIED SPEAKER:
It's in the work in progress category for right now. We'll make a final
determination based on if we go out and drill the wells, what happens to that or
....
BRAD LOOFER:
Okay. Just lastly, you know, it looks to me like the price paid for Westport
seems high. I mean, I look at the PV-10 value in Westport 10K and it's 2.5
billion and we take out liabilities, we add in other assets, we get 1.4 billion
and that's based on $30 royal and 550 per M for the life of the reserves and
then Kerr-McGee looks like they paid 1.1 billion in addition to that, and then
yet in the development costs for the probable and the possible, I'm getting
about 750 per BOE. Probable and possible, even in this market seems very, very
high. How do you look -- I guess my question is how do you look at the
acquisition in relation to those values?
UNIDENTIFIED SPEAKER:
Well, I think the key is the probable -- the low risk probable and possible
layer that we see associated with this transaction. We're, as part of the
process, reviewed in detail each of Westport's key fields. We went through the
proven, probable and possible resource potential associated with each of those
fields and so we are extremely confident that the value that the probable and
possible represents. In our presentation on -- in New York last month we went
through a breakdown of our purchase price by reserve layer. We did assign and
total about 927 million dollars to the probable and possible layer, threw out
about 300 hundred million dollars to the exploitation and exploration layer. And
when you do that, it looks like we paid about $3.09 for the probable and
possible and about 60 cents per BOE for the exploitation and exploration layer.
And again, that is based on our very detailed assessment. So we feel extremely
confident that there is a great value associated with those layers based on our
detailed assessment.
BRAD LOOFER:
So, Dave, what you are saying is you think 300 equivalent on probable and
potential is you think conservative?
DAVID HAGER:
I could not hear you real well.
UNIDENTIFIED SPEAKER:
The 300 million probable and possible resource potential?
UNIDENTIFIED SPEAKER:
Yeah. No, obviously we applied the risk factor as part of our analysis, but I
can tell you that overall, we felt comfortable with the vast majority of those.
BRAD LOOFER:
Okay.
UNIDENTIFIED SPEAKER:
I think the other thing is, of course, the hedges, I know you have given us the
SEC numbers, but we have the hedges in place with the callers that give us the
floor prices at $5 gas in '05, 475 in '06 and then oil, 28.50 in '05 and 27 in
'06 and then with the further upside associated with those hedges with the
callers.
UNIDENTIFIED SPEAKER:
I might add also that a lot of these probables and possibles are either
associated with the Greater Natural Buttes fieled we had, which we feel has
great similarities to our Wattenberg field and Wattenberg is an area where we
have done a look back on that acquisition. We have been able to add 350 BCF, we
have done over 1100 projects, we have increased the project inventory and
increased the value of that acquisition by 250 million dollars through our
activities. So we feel very confident we can do similar type things at Greater
Natural Buttes. We also see value in other areas in the gulf coast area. There's
a lot of high quality probable possible and exploitation exploration
opportunities there. And don't forget, they also have an override on Tahiti in
the Gulf of Mexico, which is still sitting in the probable category.
LOUISE:
And as a reminder, ladies and gentlemen, that is star one to ask a question.
Your next question comes from Mark Gillman from Benchmark Company. Please
proceed.
MARK GILLMAN:
Guys, good morning. Can you hear me okay?
UNIDENTIFIED SPEAKER:
Hi, Mark. Yep.
MARK GILLMAN:
Dave, on Northwest Milne, can you give us an idea the oil column that's
encountered in both the number one and number two and whether you hit an oil
water contact on the number two?
DAVID HAGER:
No, We did not hit an oil water contact on that well. We have drilled that well
considerably down depth. It's not a thick column as far as stratographic column,
but we did say we drilled the well 9,000 feet to the southeast of the number one
well. It was considerably down depth. So we think we have a pretty big aerial
extent we are dealing with here. Again, as I said to David Connie, that the main
question will be the rates that we can get from horizontal wells, which we plan
to use for our eventual development.
MARK GILLMAN:
You are reluctant to talk specifically about the column, Dave, on the one and
two?
DAVID HAGER:
Yeah. I'm going to hold off on that right now. But I can tell you that, again,
we feel we have proofed off on a big aerial extent. We have a potential large
resource in place. I would rather get a few more well penetrations out there to
really solidify all the numbers before we get too specific on it.
MARK GILLMAN:
The Sag Rivers production history elsewhere on the slope, can you discuss that a
little bit?
DAVID HAGER:
Yeah. The Sag River is a formation and has been productive elsewhere on the
slope. It's not the main producer, but it has produced in other areas out there.
We think there's certainly certain analogies with the Alpine field out there and
the Sag River production out there, and it's a solid producer. It's not the
number one producer, but we think that it can have the qualities, it can make an
economic project.
MARK GILLMAN:
Just one or two others if I could. I noticed in the financials, if I read it
correctly, that you have some assets held for sale and modest reported loss.
What are those assets held for sale and what kind of production is associated
with them?
UNIDENTIFIED SPEAKER:
I don't have the specific assets, Mark. I mean, there's some U.S. onshore, very
marginal volumes and resources associated with those.
MARK GILLMAN:
Okay. That's small numbers?
UNIDENTIFIED SPEAKER:
Yes. The investitures that we have done over 2002 and -3 are substantially
complete. There may be minor ones, but they would not be expected to impact our
production forecast going forward.
MARK GILLMAN:
Okay. And just one for Bob. To cancel working capital use in the first quarter,
is that, Bob, that timing, is that going to reverse over the course of the year?
BOB WOHLEBER:
Yeah, it is. And that's why I wanted to point that out. As I said, about 218
million dollar change in working capital. About 130 million related to the
payables. Our capital spending was down, as you know, in the first quarter. We
have generally been running the 275 to 300 million per quarter and we are about
145 million total, so most of it's there. Also within our working capital we
have our tax payables and we had about 70 million dollars of cash taxes paid.
The final element is really an inventory, slight build-up in inventory in the
chemicals in the second quarter as well. So those would be the main elements of
218 million. For the year, Mark, we really see it coming down and expect to be a
slight use of working capital for the year in the 50 to 75 million dollars, most
of that related to cash taxes.
MARK GILLMAN:
Thanks, Bob, appreciate it.
BOB WOHLEBER:
Sure.
LOUISE:
Your next question comes from Bejou Pranshel (phonetic) from Bank of America.
Please proceed.
BEJOU PRANSHEL:
Hi, Rick or Dave. On the San Jacinto well, can you tell me where it came in
relation to predrill expectations and also what is now the timing for finalizing
a development option for that whole area and when we can expect first production
from there?
UNIDENTIFIED SPEAKER:
Yeah. The San Jacinto prospect, we gave it predrill estimates of 90 to 180 BCF
equivalent. We are just now finishing the logging program on that, so we -- as
Rick said, we feel it's meeting our expectations, but it's really, I think, too
early in our analysis to say exactly where in that range we may be, but we're
confident it's somewhere in that range. As far as the overall Atwater Valley,
we're diligently working with the other operators and nonoperators in that -- in
the area to come up to a feasible development solution. It is somewhat complex
with the number of companies involved, I will tell you, but we're move forward
and we still feel confident that we'll reach a development solution sometime
this year. And first production, I don't have an exact date for you, but you can
anticipate it's going to be probably somewhere two and a half, three years after
that decision is made.
BEJOU PRANSHEL:
Okay, thanks.
LOUISE:
And as a reminder, ladies and gentlemen, that it's star one to ask a question.
And I have a question from Mark Gillman from Benchmark Company. Please proceed.
MARK GILLMAN:
All right, guys, since the call seems to be just a little bit quiet. Bob, do you
have a capitalized interest number for the quarter? Also did you accrue or book
any PRT, also a clean DD&A number would be appreciated for the first quarter, if
you could.
BOB WOHLEBER:
Yeah, 4.3 million capitalized interest. PRT was 1.7 and DD&A, are you talking
about the total cash allocation for DD&A and accretion, 210 million, which is
DD&A plus the accretion total.
MARK GILLMAN:
And that's exclusive of any impairments or --
BOB WOHLEBER:
Yes. Yes.
MARK GILLMAN:
-- sales or anything?
BOB WOHLEBER:
Yes. There's another 13 million for the impairment.
MARK GILLMAN:
Okay, thanks.
BOB WOHLEBER:
Sure.
LOUISE:
As there are no more questions at this time, I would like to turn the call back
to Mr. Buterbaugh for his closing remarks.
RICK BUTERBAUGH:
Thank you, Louise.
A replay of this call is available temporarily through the company's
website and can be accessed at www.kerr-mcgee.com. Details are available on our
website. We will host an interim conference call on Wednesday, May 26, 2004 at
10:00 central to update our expectations for the second quarter. Details about
this and future interim calls, as well as information on upcoming presentations
by members of the company's senior management, will be posted on the company's
website.
Thank you for your time and continued interest in Kerr-McGee this morning.
This concludes our call.
###
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