EXHIBIT 99.3
NOBLE ENERGY INC.
CONFERENCE CALL FOR FEBRUARY 3, 2004 @ 10 A.M. EST
CHAIRPERSON: GREG PANAGOS
EMAIL TRANSCRIPTION TO: JPIPPENGER@NOBLEENERGYINC.COM
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OPERATOR:
Welcome to the Noble Energy 2003 fourth-quarter results conference call. As a
reminder, this conference call is being recorded. I would now like to turn the
call over to Greg Panagos, Director of Investor Relations.
GREG PANAGOS:
Good morning, ladies and gentlemen. Welcome to Noble Energy's fourth-quarter and
full-year 2003 earnings conference call. I'm Greg Panagos, Director of Investor
Relations, and with me this morning are Chuck Davidson, our Chairman and CEO,
and James McElvany, our CFO. Today we'll be going over Noble Energy's
fourth-quarter results. James will go over financial results and Chuck will
discuss our operating results and the outlook for the company.
Please note that we will be making some forward-looking statements. So I'd like
to paraphrase the final paragraph of our press release, which states that this
conference call may include projections and other forward-looking statements
within the meaning of the federal securities laws. Any such projections or
statements reflect Noble Energy's current views about future events and
financial performance. No assurances can be given that such events or
performance will occur as projected and actual results may differ materially
from those projected.
I would also like to point out that, in the course of our discussion this
morning, we're likely to refer to certain measures such as discretionary cash
flow or EBITDA. While these are not generally accepted accounting principles
measures of accounting performance, we believe they are good tools for internal
use and for the investment community in evaluating the company's overall
performance. Now I'll turn the call over to James McElvany to discuss financial
results.
JAMES MCELVANY:
Thank you, Greg, and good morning. As many of you are aware, during 2003 Noble
Energy designated five non-core domestic asset packages to be sold. We
classified these packages as discontinued operations. Our reported 2003 results
included net income from discontinued operations below the operating income
line. We have added a table in the back of the earnings release called
"Discontinued Operations Summary" that provides summary income statements and
volumes for each quarter and the full year for discontinued operations. To see
how Noble Energy would have looked if these five property packages had not been
classified as discontinued, you need only to add them back to our consolidated
or domestic operations totals.
Under current SEC guidelines, public companies are required to treat all assets
held for sale as discontinued once they meet certain specified criteria. As you
would expect, given the nature of our business, such accounting treatment will
inevitably create complexities in reporting for quarterly comparisons. In Noble
Energy's case, the five domestic property packages were dropped into
discontinued operations over the last three quarters of 2003. Because the
packages were added to discontinued operations in different quarters, we were
required to restate discontinued operations in each of the previous quarters as
we added the packages, making quarterly comparisons complex and of limited
value.
However, now that all the property packages are in discontinued operations, the
fourth-quarter discontinued operations summary can be used in your evaluation
for each quarter for 2003.
One additional note, we have included a footnote in our discretionary cash flow
schedule identifying the amounts of deferred income taxes that could not be seen
in the below-the-line items reported net of tax (such as discontinued operations
and change in accounting principles). We hope this footnote will help you with
your cash flow analysis.
Before I get into the financial performance, I'd like to take a moment to talk
about our fourth-quarter impairment and reserves. I am acutely aware that there
has been concern in the markets lately about reserve revisions. I would just
like
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to point out that the impairment we took in the fourth quarter is quite small in
terms of revisions of proved reserves. The bulk of the impairment related to a
specific property for a specific reason, namely the less-than-expected results
from recompletions and remediation activities on our East Cameron 338 property
in the Gulf of Mexico.
As stated in our press release, a total of 2.2 million barrels of proved
offshore oil equivalent reserves, or less than one-half of 1% of our total
year-end 2003 reserves, were removed from our books. While we cannot predict
with complete accuracy how wells will respond to workovers or recompletions, and
while positive and negative revisions will always be a reality in our business,
we do not anticipate significant revisions to our reserves and believe our
reserves are recorded in accordance with SEC guidelines.
Turning to our financial results, Noble Energy reported a fourth-quarter net
loss of $21.1 million or 37 cents per share, compared with net income of $16.8
million or 29 cents per share for the third quarter. Discretionary cash flow for
the fourth quarter 2003 was $171.5 million or $3.02 per share, the company's
highest quarterly discretionary cash flow since the first quarter of 2001.
Fourth-quarter discretionary cash flow was up 12% compared to $153.2 million or
$2.71 per share last quarter.
The decline in reported net income compared to the third quarter was due to the
impact of several one-time non-cash charges. The first was a loss on the sale of
assets. The second was the writedown of our investment in Vietnam. And third,
was the property impairment. That's the property impairment I mentioned earlier.
Cumulatively, these charges cost the company $56.5 million of net income.
Excluding the after-tax impact of these charges, Noble Energy's fourth-quarter
income would have been $31.7 million [sic $35.4] or 56 cents per share [sic 62
cents per share] per share. We also realized a $14.3-million current tax benefit
as a result of the $20.2-million Vietnam write off for a net financial impact of
$5.9 million.
During the fourth quarter in discontinued operations, we recognized a non-cash
writedown to market value on our offshore package, a loss on disposition on our
California package which was partially offset by a gain on disposition from our
southern Oklahoma properties, for a total loss of $45.8 million pretax. The
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earnings impact after tax was $29.8 million or 52 cents per share, and again the
detail of this is in that schedule at the back of the press release on
discontinued operations.
Looking at the segment reporting schedule by country, in order to gain a clearer
picture of how our domestic operations performed in the fourth quarter relative
to the third quarter, I added discontinued operations back to our reported
results. As a result, reported domestic operating income would decline $83
million, reflecting the decreased... excuse me, the increased right down to fair
value of assets held for sale, loss on assets sold and the impairment. Excluding
the effect of the writedown of assets to fair market value and the loss on
disposition and impairment, operating income declined $12 million compared to
the third quarter from $50 million to $38 million.
Revenue was about $9 million lower this quarter compared to last due to lower
realized natural gas prices and lower other income. Higher exploration expense,
which increased nearly $7 million, also contributed to lower operating income.
However, that was partially offset by lower DD&A and SG&A expenses.
Fourth-quarter domestic production was up slightly, about 800 barrels of oil
equivalent per day, compared to the third quarter.
International operating income decreased $3 million compared to the third
quarter. Adding back the Vietnam write-off however, resulted in a
quarter-to-quarter increase in international operating income of $17 million.
Our North Sea operations accounted for $6 million of this increase. That
resulted from a combination of higher production volumes, higher realized
natural gas prices and lower DD&A expense. Marginally higher transportation and
exploration expenses partially offset these improvements.
In Equatorial Guinea, operating income was up close to $5 million compared to
the third quarter, nearly all of which was due to higher liquids production.
Higher realized liquids prices also contributed, though they were offset by
increased oil and gas operating expenses and slightly lower methanol income,
resulting from slightly lower methanol prices. Methanol prices declined three
cents per gallon during the quarter. Other international accounted for the
remaining $6 million increase in operating income.
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In Ecuador, operating income increased $2 million as we moved into the dry
season, reflecting a 26% increase in power production. Lower expenses across the
board contributed the remaining $4 million to increase other international
operating income.
Our overall income tax rate for the fourth quarter was 42%. This rate is the sum
of the tax provisions for both continuing and discontinued operations. The
nearly 100% rate for continuing operations, when adjusted for the impairment and
write off of Vietnam, will get you down to the 42% effective overall rate. The
overall income tax rate for the full year 2003 was 36.8%.
Turning to the balance sheet, as of December 31st, 2003, total debt decreased
$89 million from year-end 2002. The reduction was from a $50-million reduction
in our credit facility, a $39-million reduction in our Israeli bridge loan and
other miscellaneous debt. Long-term debt of $776 million was down $200 million
from year-end 2002. The reduction in long-term debt resulted from a shift from
long-term to short-term of our $125-million AMCCO note, about $29 million of
other debt reclassified [sic, and the rest was paid off.] Total
debt-to-capitalization at year-end was 46% compared to 50% at the end of 2002.
We did have natural gas and crude oil hedges in place during the quarter. These
hedges included two-way collars as well as the continuing 70-cent premium we had
for closing previous transactions. For the fourth quarter we had 185 million
cubic feet of natural gas per day hedged and 15,000 barrels of oil, crude. In
2004 our hedge position is somewhat lighter. We have 120 million cubic feet per
day of natural gas hedged for the year, and through the first three quarters
15,000 barrels of oil per day. In the fourth quarter of 2004, our hedge position
declined further to 5,000 barrels of oil per day. Most of our hedge positions
are two-way collars with an average floor of $4.31 per MCF for natural gas and
$24.95 per barrel of crude. The average ceilings for natural gas are $6.53 per
MCF and for crude oil are $31.16 per barrel for 2004.
Before I turn the call over to Chuck, let me take a moment to talk about our
outlook for 2004. With 2003 behind us and our capital budget of $460 million for
2004 approved by the Board of Directors, we felt that it was time to provide a
complete update of guidance for the upcoming year. Hopefully, most of you have
seen our capital expenditure press release and the outlook section included
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in that release. In our guidance for 2004, we are trying to give reasonable
ranges for estimated growth in production volumes and expenses. We believe these
ranges have a reasonable degree of certainty of being achieved.
Average production in 2004 is estimated to increase between ten percent and 17
percent compared to 2003 volumes.
Noble Energy's production profile will be impacted by several factors including:
o The timing of production increases in Israel and Phase 2A in
Equatorial Guinea during 2004;
o Seasonable variations in rainfalls in Ecuador also affect the
company's natural gas to power projects; and
o The potential weather related shut-ins in the U.S., Gulf of Mexico and
Gulf Coast usually occurring in the third quarter.
To give you a sense of timing for new production in 2004, let me give you some
highlights of the major projects we plan to bring on stream in 2004.
o Our project in Israel was commissioned in the fourth quarter of 2003
and sales are expected to reach 40 million cubic feet per day, net to
Noble Energy, by the end of the first quarter of 2004. Production is
projected to continue to increase throughout 2004, adding another 30
to 50 million cubic feet per day, net to Noble's interest.
o Phase 2A condensate expansion in Equatorial Guinea started up during
November 2003 and is expected to add nearly 10,000 barrels of oil per
day equivalent, net to Noble Energy, by the end of the first quarter
of 2004. Phase 2B is scheduled for completion by year-end 2004, but is
not expected to contribute production until 2005.
Compared to the full year 2003, costs and expenses may vary as follows:
o Exploration expense is expected to range from $135 million to $150
million. Our exploration budget for 2004 is estimated to be flat with
2003, even with a 15 percent reduction in our overall capital program
of $460 million.
o Selling, general and administrative expenses are expected to range
from $1.30 per BOE to $1.50 per BOE. We expect aggregate SG&A to be
flat
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with 2003 with some moderations in pension, medical and corporate
governance costs, but down on a unit basis as production from
international projects ramp up.
o Oil and gas operating expense is expected to range from $4.35 per BOE
to $4.65 per BOE, more or less in line with our 2003 unit rates.
o Depreciation, depletion and amortization is expected to range from
$7.40 per BOE to $7.75 per BOE. Reduced DD&A is driven by three
factors: 1) the new lower cost international production coming online,
2) the sale of properties in 2003 with relatively high DD&A rates, and
3) the impairment we incurred in the fourth quarter that alone lowered
DD&A about ten percent.
o An effective tax rate of 38 percent to 48 percent is expected, with
deferred taxes ranging from ten percent to 30 percent.
The above estimates do not include the impact of any possible asset purchases or
sales. And with that, let me turn the call over to Chuck.
CHUCK DAVIDSON:
Thanks, James, and good morning to everybody. Certainly it's been a busy year
for Noble Energy, and we have accomplished a lot. Even more important is that we
find ourselves now in a very excellent position with new low-cost and
high-margin production rapidly coming on stream. James has covered the
financials, and I won't repeat them once again. We see in this quarter
discontinued operations accounting has somewhat obscured very strong underlying
fundamentals. As James noted, the picture will rapidly clear now that all of our
property's packages have either been sold or are in the discontinued operations
category. It allows us to focus on the continuing operations piece, and that's
where we show excellent progress.
So staying above the line and looking at continuing operations, our reported
production was up seven percent over 2002. Excluding the impact of property
sales and discontinued operations, overall production increased about four
percent over 2002, which was in line with the lower end of the guidance that we
provided you a year ago.
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But what that does mean, if you look behind the numbers, is that the properties
we targeted for sale were declining in production while our core areas grew in
production. No surprise there.
I'm also pleased that the continued trend of stable domestic production
continues. On a continuing operations basis, domestic production was flat with
2002. Also, if you look at it, again on a continuing basis, fourth quarter
domestic production was up 4.7 percent versus the third quarter, and it was up
8.9 percent versus the fourth quarter of 2002. As James noted, costs were, by
and large, in line with our plans. During the year, of course, we started
production in China, we had our first full year of operations in Ecuador; we
completed and commissioned our natural gas project in Israel; and, in November,
commenced production from Phase 2A in Equatorial Guinea. I'll have more on these
major projects regarding Israel and Equatorial Guinea in a moment.
Our finding and development costs are still too high, but there are some unique
factors that came into play in 2003. Most importantly, and we discussed this in
our reserve replacement press release, just over 50 percent of our overall F&D
costs for 2003 went towards developing reserves in Israel and Equatorial Guinea
where the reserves were recognized in prior years. That should not be a
surprise. However, what it does mean is that our proven undeveloped reserves for
our whole company, as a percentage of total reserves, have now dropped from
where they were before to about 28 percent. So, at the end of this year we'll
have about ten percent of our reserves classified as proven undeveloped for the
company. And that really is in line with the fact that we're completing the
major international projects and bringing those into the development stage.
I would add, though, that even with 90 percent of international capital going
towards development projects, international will still manage to replace its
production this year. As most of you know, on international ventures you really
need to look at these kinds of statistics on a multi-year basis, especially now
that we're wrapping up the majority of the spending on these projects. And for
instance, and when we look at our international three-year reserve replacement
costs they're at a very reasonable $4.50 per barrel of oil equivalent.
Domestic onshore, we noted we looked to replace about 118 percent of our
production there at a cost of about $1.48 per MCF. That's pretty much in line
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with our expectations. There are no significant property acquisitions in these
numbers for 2003. This really represents our base core programs onshore.
Reserve replacement offshore in the Gulf of Mexico is a different matter. Over
the past two years, we've dramatically reduced our capital allocated to the
Gulf. Last year less than 25 percent of our overall F&D capital went into the
Gulf. Of that capital, just over 50 percent was tied to projects that were
either developing reserves, such as recompletions on the shelf and our deepwater
discovery that is not yet booked. So having said that, there is also a little
bit of good news on the Gulf of Mexico. Our Lorien discovery, that we announced
in July, has not been booked and it will be dependant on an appraisal well that
we're expecting to drill this year, which will lead to likely bookings in 2004
and clearly improve results for offshore.
As James noted, the performance revisions in East Cameron didn't help things,
but that's behind us. Unfortunately, it happened on a very high cost property
that tripped the impairment trigger.
So we enter 2004 at a very strong pace. Production volumes are coming up nicely.
Many of our major projects now are seeing capital investments winding down -
China, Ecuador and Israel are certainly notable in this category. Equatorial
Guinea, Phase 2A, has started up and is ramping up. Two B, the second phase of
that project, is scheduled for completion by year-end. So our international
capital commitments are declining rapidly, and our free cash flow is growing
significantly.
Our domestic business has fully implemented disciplined business processes that
have stabilized our production and will certainly lead to improved margins. So,
I think we now find ourselves in a very good position in terms of improved
financial and operational flexibility.
Now, I'll just turn back and look a little bit at our full-year and
fourth-quarter results. As James noted, commodity prices across the board
strongly helped us throughout the year. Oil and gas revenues for the full year
were up some $245 million versus 2002, mostly due to higher crude and gas
prices. But increased volumes also contributed to this revenue line as well. And
clearly, our balance
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sheet is now stronger, with our total debt-to-book capital ratio dropping four
full percentage points this year to 46 percent.
Beyond commodity prices, though, I think we also need to take credit for a good
job of maintaining our discipline and controlling expenses and managing our
capital programs. At the beginning of the year, we announced a capital program
of $510 million. Ultimately, we spent about seven percent more, most of it
having to do with the timing of some international projects. And we also added a
little bit to our program in the Gulf Coast onshore area, which was doing quite
well. As a result, we've announced our 2004 capital budget is, of course, down
as we complete some of the major expenditures.
I'd also like to say that we did a good job on the expense side as well. When we
look at exploration, SG&A and DD&A, we were successful in staying within the
ranges that we laid out to you a year ago. There were two exceptions - SG&A that
was about ten percent higher than we anticipated. And oil and gas operating
expenses that were primarily driven by the higher commodity prices that, in
turn, drove higher production taxes for our onshore production.
Fourth-quarter production was in line with our expectations. Reported
production, that's from continuing operations, was just about 95,000 barrels a
day compared to about 89,000 barrels a day in the third quarter. The increase
was in several areas resulting from start-up and new production in the Gulf of
Mexico, the start up of Phase 2A in Equatorial Guinea, and some increased
production in the North Sea after the seasonal slowdown we encountered in the
third quarter.
Reported production volumes for the full year increased about seven percent, and
again I'm staying above the line on continuing operations. International volumes
increased nearly 7,000 barrels a day for the full year 2003 versus 2002, and of
course that was primarily because of our major projects that we were adding in
the international area. And as noted earlier, domestic volumes were basically
flat year-over-year.
James discussed our range on production guidance for the full year. It may sound
like a broad range, but we do believe that we have realistic lower and upper
limits to reflect the uncertainties, primarily of a few large projects that are
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coming on stream this year. And that's most notably having to do with the
ramp-ups of production in Israel as well as the ramp-up of production in
Equatorial Guinea.
The upper end of the range ties closely to ramp up schedules that we've outlined
for Israel and EG. We have assumed that Phase 2B in Equatorial Guinea will start
at the end of the year and will have little impact on production for 2004. So an
early start on that would be upside beyond the range provided. And the lower end
of the range would accommodate a delay in, for instance, reaching full rates in
Equatorial Guinea or a slower pace in Israel.
Even though we are in a take-or-pay phase in Israel, and I'll talk more about
that in a moment, our production stats will not include production until it's
actually delivered. So even though we collect cash under take-or-pay, we don't
include those volumes in our production, and we have excluded January volumes
from our production guidance numbers. And as usual, no acquisition volumes are
included in our production guidance. And with the programs that we have in
place, we expect the domestic production to remain essentially stable from the
levels that we've had during the past year.
During last quarter's conference call, I mentioned we were well along the way on
marketing five asset packages held for disposition. We also provided an update
on this program in a release in December. Overall, our total property
divestiture program represented about six percent of our reserves and about nine
percent of our production. We've now closed on the sale of four of the five
packages and we're working to close the fifth package, our offshore package,
during this quarter. Overall, the total package is still expected to generate
proceeds in excess of $110 million.
As noted in our outlook, we expect capital expenditures this year to be about
$460 million. Again, down because of the completion of some major international
projects. About 35 percent of our capital budget will be going into exploration
and 65 percent into production and development projects. Domestic spending is
expected to be about $270 million, with the remaining going towards
international projects. Just under one-half of the international spending is
budgeted for completion in Equatorial Guinea and the rest for drilling North
Sea, Latin America and the Far East.
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Now I'd like to go through a few of our areas as we kind of ramp up the
operational outlook before we open up for questions. And I'll start in the
domestic area. And as I go through this, I'll not only be talking about 2003
results, but also be giving a flavor for what we see happening in 2004.
Domestic onshore, we actually accelerated our activity in drilling programs in
the fourth quarter. Overall, in 2003 our domestic onshore business drilled a
total of 79 [sic 78] wells of which 51 [sic 50] were successful for an overall
success rate of 64 [sic 64] percent. The bulk of these wells, there were in fact
44 [sic 45] of these wells, were drilled in the Gulf Coast region where we
focused on the programs in the Aspect AMI and in other areas that we focused on
in the past few years-Wildcat Ridge and South Texas and Duval County.
And just as a highlight, because it did have quite a bit of activity in the
fourth quarter, in south Texas and Duval County, we've now drilled six wells of
which five have been successful. This is a program that's been identified
through a proprietary 3D seismic survey that we acquired in 2002. Again, it's
proprietary. We carry a high interest in this area with some 85 to 100 percent
working interest on the wells. With the wells that have been completed so far,
we've already added about 2,700 barrels a day equivalent per day, gross
production, by the end of 2003. And with the success we've had, we're planning
to follow up with a number of wells in 2004. Currently we have plans for at
least six more wells of which five will be exploration.
In Wyoming in the Wind River Basin, we've completed the well on our Ironhorse
prospect. The initial test well was drilled to a depth of about 15,000 feet when
testing the Cretaceous and Lance objectives. We have gotten gas production from
these tests, and it is a low permeability reservoir. It's been testing at fairly
low rates, but we do plan to carry out an extended test program, as well as
evaluate some of the additional seismic that we've acquired in the area.
Turning to offshore, we continue to shift our focus to deep shelf and deepwater
drilling. And most of what we have spent on the traditional shelf has been in
areas to develop assets that we already have, such as recompletions on existing
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fields. And that's what results in such a high percentage of our capital going
into ongoing development projects.
We have some new projects that have come on stream that have really helped us in
stabilizing the production in the Gulf. For instance, in the deep shelf our
Mound Point discovery came on production in October, now producing about 34
million cubic feet equivalent on a gross basis, and we have a 25 percent
interest. We just now are moving a rig on in the field to drill a second well.
Also on the shelf, the Roaring Fork Field in South Timbalier started up in
September. We now have three wells producing. They're producing over 22,000
barrels a day gross production, and Noble Energy has a 40 percent interest in
Roaring Fork.
I mentioned last quarter we had interest in three deep shelf wells that we'll be
drilling, the Viosca Knoll, South Pelto and Brazos. The Viosca Knoll has been
drilled, completed, and is now producing just under ten million cubic feet per
day. Pelto is still drilling; it's below 14,000 feet. Brazos has reached TD and
logged apparent pay. We're now evaluating our completion options. During 2004,
besides these carryover wells, we plan to drill another three to four deep shelf
wells as well.
In the deepwater, the Boris Field continues to produce extremely well. This is a
field in Green Canyon 282 in which Noble has a 25 percent interest. Our two
wells there are currently producing at a rate of around 25,000 barrels a day of
oil equivalent, gross. Also in the deepwater, the Mississippi Canyon 837
discovery, a prospect we call Loon, is expected to begin production in the first
quarter. That was delayed from an earlier planned start-up in the fourth
quarter. Gross production is expected around 12 million a day of which we have
40 percent.
In 2003, as a total, deepwater production averaged around 20 percent of Noble
Energy's total Gulf of Mexico production. That's up substantially from 2002
where it only averaged seven percent of our production, clearly reflecting the
increased focus that we've placed on developing these deepwater opportunities.
In July we announced our discovery at Green Canyon 199, Lorien, and we're
proceeding ahead with our partners on looking at an evaluation and an appraisal
program for that. As was noted before, we haven't booked any reserves at Lorien;
we expect that to happen in 2004. We have a 20 percent interest in that
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discovery. Also in 2004 we expect that our partner will be proceeding ahead with
the development of the Swordfish deepwater discovery.
We've already begun the drilling of one deepwater prospect, Queen of Hearts. It
started in the fourth quarter. This is in Ewing Banks 949. It's approaching TD,
so we would expect it to be decisioned this quarter. We operate this well and
have a 52 percent interest. Looking forward in 2004, we would expect to drill
two to three additional deepwater prospects. Overall, in 2004 approximately
two-thirds of our Gulf of Mexico capital will be spent on deep shelf and
deepwater exploration and development projects.
Turning to international operations, we had another strong quarter. Operating
income was over $26 million and, of course, that includes the effect of the
$20-million writedown in Vietnam. Looking at the press release tables where we
show consolidating operating income, you can see that Equatorial Guinea was once
again the biggest contributor this past quarter. LPG and condensate operations
and methanol combined to add $22 million of operating income, up from $18
million in the third quarter. Production was up slightly from the third quarter
as well.
And when you factor in the fact that the field there in Equatorial Guinea was
down for some time in the third quarter, it's up dramatically at the end of the
year as a result of the start-up of 2A. That expansion is continuing. The
project is now adding some 10,000 to 12,000 barrels per day gross of additional
condensate. It is expected to be at the full rate, incremental rate, of around
28,000 barrels a day or 9,000 barrels a day net to our interest at the end of
the first quarter, and again that's the incremental rate over and above the
existing production in the field.
The second phase expansion, 2B, will ultimately increase our net liquids
production by about 6,000 barrels a day, and that's again expected to be
complete at the end of this year. As I mentioned last quarter, one of the
methanol plant's compressors was down for repairs. We did manage to sell
methanol from inventory. And as a result we ended up with, once again, a good
solid quarter from our methanol operations, with operating income of $7 million.
Methanol prices continue to be strong with 60 cent a gallon prices and methanol
sales volumes of around 29 million gallons.
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In late 2003, we announced we'd commenced operations in Israel, one of our
larger and more important international projects. And then a few weeks ago we
announced that we had commissioned our facility. We're still waiting for Israel
to complete the authorization process to allow gas to be transported into our
customer's facilities, Israel Electric's generating plant there at Ashdod. This
authorization has continued to be delayed due to our customer, Israel Electric,
encountering some labor issues that are really unrelated to our project.
However, as we've noted earlier, the early take-or-pay provision in our contract
became effective January 1. That substantially mitigates the financial impacts
of the delay. Regardless, we do expect approval for gas to begin flowing into
IEC shortly, and we're taking it really on a day-by-day basis for right now.
More importantly, we continued to stay focused on ways that we can increase the
volumes in Israel because of the growing demand for natural gas in the country.
We and our partners have contracted to sell, under this base contract, an
average of about 170 million cubic feet a day of natural gas to IEC over an
11-year period. And that's when it reaches its full rate which is at the end of
this year. But again, our priority this year is to finalize the marketing of
additional volumes. We've already entered into a non-binding term sheet with one
industrial user there at Ashdod in the vicinity of the power plant. We've
already contacted other parties and are looking at additional opportunities.
Israel has a number of potential industrial natural gas consumers, and they have
very strong projected annual electricity growth over the next several years.
With our facilities at Mari-B designed to produce up to 600 million cubic feet
per day, we can significantly expand production at minimal additional cost.
Wrapping up, in Ecuador our Machala power plant had strong revenues and cash
flow this year of $58 million of revenue and $34 million of cash flow. During
the fourth quarter we had operating income of a little over $2 million and cash
flow of over $10 million. Again, it's in the fourth quarter and the first
quarter of the year, that we see the highest demand for power in Ecuador, and
basically we operate under a baseload configuration. As a result of high
utilization in the fourth quarter, natural gas volumes that were delivered to
the power plant increased some 22 percent versus the third quarter.
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In 2004, as part of our overall program, we will be drilling at least three
additional wells in the field. This is to basically maintain our deliverability
and gas supplies. That presumably would carry us well into the next decade in
terms of adequate deliverability. The rig is just in the process of arriving for
that work. So, we would expect that through the first through third quarters,
we'll have activity in Ecuador as we drill to complete these wells.
In the North Sea, operating income rose to $16 million from $10 million. This is
due obviously to strong overall crude and gas prices and some lower overall
operating costs in the North Sea. And in China, production has remained steady.
The fourth quarter averaged 3,300 barrels a day. We've done a little bit of work
in the field and that's enhanced production a bit. We expect to carry out a
modest drilling program in 2004 that is expected to maintain production in
China. We have a 57% interest in this project in the Bohai Bay.
I think with that, why don't we open up the lines for questions?
OPERATOR:
Thank you. We will now begin the question-and-answer session. To place yourself
into the question queue, please press star one on your touchtone phone. If
you're using a speakerphone, please pick up your handset and then press the star
one. If your question has been answered and you would like to withdraw your
request, you may do so by pressing star two. Please go ahead if you have any
questions. Our first question comes in from Questioner. Please go ahead.
QUESTIONER:
Good morning.
CHUCK DAVIDSON:
Good morning.
QUESTIONER:
Two quick questions. First, could you break out the proved developed reserves in
the U.S. versus international? Just the rates?
16
CHUCK DAVIDSON:
Yes. Overall I mentioned on the call that we were down to about ten percent of
PUDs in total for the company, and they're doing a little work there.
GREG PANAGOS:
Domestic reserves are 30 percent of total reserves. That's proved developed and
undeveloped.
CHUCK DAVIDSON:
I don't know if you heard that.
QUESTIONER:
Yes, I got that. Maybe at some point later if you get it, just tell me what the
percent of proved developed are within the U.S. and within international.
CHUCK DAVIDSON:
I'll give you some general things, and we'll get back with some of the
specifics. The only place where we're really carrying much in the way of PUDs in
the U.S. We have the Bowdoin Field, where it's a long-lived gas field, and we
have additional locations in that field. And we do some additional drilling, and
we carry PUDs there. Most of our deepwater has been developed, but we carry
reserves in Swordfish, fairly small, as PUDs. And as I mentioned before, at
Lorien we keep unbooked, and Boris shifted.
So really when you look at PUDs in the U.S., it's fairly minimal. We do have
more reserves in the U.S. that are behind pipe because of the multi-zones in the
Gulf of Mexico. We have some proved developed, non-producing that's behind pipe.
In International, we still have a little bit proved undeveloped in Israel, some
proved undeveloped in Ecuador, some proved undeveloped in Argentina and that's
basically it. Most everything in EG is now shifting to proved developed. We
still have reserves associated with the 2B project that are proved undeveloped.
And there's a ton of probable reserves, and they're non-booked reserves
associated in EG with additional gas resources. We'll have the details when we
put together all the schedules on our 10K for all those pieces, but that gives
you the general feel for where they are.
17
QUESTIONER:
Great. Thanks. And then what's the timing on the two to three additional
deepwater prospects this year that you didn't mention, as well as the timing of
the Ironhorse test results?
CHUCK DAVIDSON:
The Ironhorse is undergoing tests right now. So we're flowing gas, but it's at
low rates. They want to continue to flow it because it's long-term. You really
have to see what the decline rates are going to be, what's going to be the mix
on it and things like that. So that's ongoing through the early part of this
year.
Deepwater drilling is really - as soon as we get the prospects ready, I would
expect that a number of prospects will be generally equally spaced through the
year. I do know that we're getting another one ready with our partner right now
that may follow. It will start late in the first quarter, or early in the second
quarter.
QUESTIONER:
Thank you.
CHUCK DAVIDSON:
Thank you.
OPERATOR:
Thank you. Your next question comes from in from Questioner. Please go ahead.
QUESTIONER:
Good morning, guys.
CHUCK DAVIDSON:
Good morning.
QUESTIONER:
Actually I have a couple of questions. One, on the base production for 2003 from
what you are using that ten to 17 percent growth rate, what is that base
production. Because we have a lot of moving numbers during the course of the
year, whether it's excluding all of it or including part of it.
18
CHUCK DAVIDSON:
The base on which it is set is what would be the continuing operations number. I
can't give you the exact number right now but I believe it's 92,100 barrels of
oil equivalent per day. That's the base. And of course, what's been excluded is
all the properties that were held or sold, which is roughly around 9,000 to
10,000 barrels a day equivalent at the end of the year. So if you're kind of
looking at pre-property sale versus post-property sale, and looking at what's
held down in discontinued operations, I think down in discontinued operations we
have just under 10,000 barrels a day equivalent of production.
QUESTIONER:
Okay. You answered the question because just the sales of properties occurred
during the course of the year, so some of the volumes were in there, some of
them weren't.
CHUCK DAVIDSON:
I agree with you. The discontinued ops we agree is very confusing and appreciate
you asking the clarifying question. Did you say you had one more question?
QUESTIONER:
Yes, one more just on Israel. Could you give us a sense as to during the course
of January and now into February you've got a take-or-pay fee coming back to
you. Can you give us a sense as to what that might be and where that might be
reported from an accounting standpoint, because you won't have volumes
associated with it.
CHUCK DAVIDSON:
Right. The gross invoice for January take-or-pay was about $6.4 million, and so
net to us be around $3.1 million net. And you're correct, we will collect cash
for this. That invoice has been delivered to IEC, and it's the invoice on a
monthly basis. And I think it's payable by about the third week of this month in
February. James I think will just comment on how he records the entries on that.
JAMES MCELVANY:
That'll go into our other deferred credit account.
19
CHUCK DAVIDSON:
Just another clarification for those who are tracking take-or-pay, because the
industry probably hasn't had take-or-pay contracts in a long time. This one was
important to us because of the investment we're making in Israel and just
because there could be an issue where something might slow their ability to take
gas. They do have the ability to make up this volume. And in this phase of the
contract, they can begin to make up these volumes starting in the second
contract year, which is October, beginning October 1. And the way they do that
is by increasing their minimum pay. They nominate higher than their minimum pay
to start making up.
QUESTIONER:
Actually, one last very quick one. Just in Ecuador, the additional wells to be
drilled, the three or four wells, I'm assuming you're not going to be adding
reserves there. You just want to make sure you have additional deliverability.
Is that correct?
CHUCK DAVIDSON:
We would expect to add some reserves there. We have taken, I think, a very
conservative approach in our booking of proved reserves in Ecuador. And we do
have some proved undeveloped there. But we left a lot in the probable category
and felt that we would wait until we brought the rig back to develop those. And
so it will be a mix of shifting some reserves from proven undeveloped. But we
also expect that we will have some exposure to proven reserve additions as well.
QUESTIONER:
Right. Thank you. Thank you very much, guys.
CHUCK DAVIDSON:
Thank you.
OPERATOR:
Thank you. Your next question comes in from Questioner. Please go ahead.
QUESTIONER:
Hi. Thanks. Good morning.
20
CHUCK DAVIDSON:
Good morning.
QUESTIONER:
Just curious about what kind of timeframe you would expect more of a
stabilization on the domestic gas front. I mean obviously, you know, 2003
brought pretty poor production replacement in the U.S. And you've spoken to the
reduced cap ex in the Gulf of Mexico. I just want a sense on sort of the
near-term here in the U.S. And then the related question would be an update on
the deep shelf as a play. I heard you say two-thirds of your Gulf capital is
going to be directed to deep shelf and deepwater. But a couple of industry
players seem to be broadly backing off plans in the deep shelf, and I just
wondered what your take is today.
CHUCK DAVIDSON:
Yes. In terms of the gas front, from our standpoint when we forget about
properties that we're selling, which were higher decline rate properties, for
instance when we look at domestic onshore we're holding our own there. Gulf of
Mexico clearly is a different issue. And as you've seen on our stats, we've
actually been adding in the Gulf of Mexico quite a bit of oil production. And as
we brought deepwater production up, it's become a greater component of our
overall Gulf of Mexico production.
So I think for us, and also for the industry, we're still struggling with the
old issue of finding and supplying additional volumes of gas. It continues to be
a bit of a struggle, but we still take the view, and I still take the view, that
North America is relatively mature and that we have to constrain capital.
Clearly, with the amount of capital constraint that we apply to the Gulf of
Mexico, we were not in a position to replace production through a drill bit
approach. It was more developing what we had and then continuing to build on the
deep shelf and the deepwater programs that do give us exposure going forward.
I think for Noble, clearly the answer in terms of having decent reserve costs,
decent metrics in the Gulf of Mexico is dependant on a deepwater program and
somewhat a deep shelf program. Deep shelf for us is a little different than
others. We have stayed in the range of drilling 15,000 foot to 20,000 foot
wells. Our success rates have continued to stay in the ranges that we've talked
to you
21
before, of 50 percent to 60 percent success rate. I think the challenge on the
deep shelf continues to be that reservoir quality can be problematic, and that
you've got to absolutely avoid drilling problems. That's been mitigated some in
the recent period because rig rates and drilling costs are down, but I think the
deep shelf has a bit of exposure if we see drilling costs go up dramatically
there. I think that program stays a risk.
That's why we continue to move and keep really two fronts going in the Gulf of
Mexico, and that's both deep shelf and deepwater. If I was going to take my
choice, the program right now that's really been helping us is the deepwater
projects that are close to infrastructure, sub-sea tiebacks that have good
metrics and bring production on quickly.
The other thing that is helping a little bit, but probably not going to make a
major difference is the MMS did finalize it's incentive program for deep shelf
royalty relief. And that should help some operators in terms of part of their
programs. But I don't think you would expect that to make a huge difference in
the drilling programs.
QUESTIONER:
Do you have a well count as to how many deep shelf wells you're going to drill
this year versus last? I apologize if I missed that.
CHUCK DAVIDSON:
It will be approximately the same. Total well count deep shelf will be four to
six. We would expect that's fairly comparable with what we had in 2003. There
might be a one well difference there. In the deepwater, we expect to drill more
deepwater wells this year than 2003. In 2003 as we restructured things, we ended
up drilling one deepwater prospect and it was successful. That was Lorien.
This year, that will step up significantly and, again, I think that positions us
much better to show improved results in the Gulf of Mexico in the parts that
we're focused on.
QUESTIONER:
Very good. Thanks.
22
CHUCK DAVIDSON:
Thanks.
OPERATOR:
Thank you. Your next question comes in from Questioner. Please go ahead.
QUESTIONER:
Good morning. I wanted to hear a little bit more about Ironhorse in terms of the
number of wells or prospects you've identified in that area more broadly.
Secondly, would you talk a little bit about your potential exposure to the ultra
deep shelf. There's been a lot of industry speculation about the promise of some
of that in the shallow water Gulf of Mexico. And then lastly, just briefly touch
upon the incremental reserve additions that you could associate with the
capacity that you have offshore Israel. Thanks.
CHUCK DAVIDSON:
In terms of Ironhorse, again the area that we have there is around 27,000 to
28,000 gross acres, and so it's a fairly large area. We're exploring a couple of
formations there. There's just tight gas, non-conventional gas. We've drilled
one well. We have acquired some additional 3D seismic, and we're now looking at
how that seismic ties into the particular well we drilled and the test results.
So I think it's too early to promise when we might be drilling another well
there, or if we'll be drilling another well there. I think it all depends on the
evaluation results. But it's as we expected, it's an area that contains gas and
the key will be to achieve commercial rates from it.
QUESTIONER:
I guess to narrow the question, how many more ideas or possibilities have you
identified on that acreage position which would then...
CHUCK DAVIDSON:
Without getting into a lot of technical detail, there appears, through the
seismic, to be areas that are better identified than others and it's tying those
in, and then understanding the degree that productivity might be enhanced as you
move to those areas. It's not just a big formation that you can just drill up on
28,000 acres. You really have to look at the faulting, look at the change in
reservoir
23
character and potential reservoir quality as you go through. So it's still a
large opportunity. It's too early to tell where it might lead ultimately.
QUESTIONER:
Okay.
CHUCK DAVIDSON:
On the ultra deep shelf, where we are there, we have generally not gone towards
the ultra deep shelf. And when I think of ultra deep I'm thinking of 25,000 to
30,000 feet. Potentially high upside opportunities there, clearly high risk
opportunities, high potential drilling cost opportunities. We have not focused
our portfolio there. We may have a few that approach those depths, but we have
generally not pushed them into our drilling program near term. Right now, as we
go through our exploration processes, we can't seem to see the risk/reward that
comes out and which can compete against other things.
I think, in terms of Israel, we look at other resources there that are unbooked.
We have probables of somewhere around, on a gross basis, about 200 BCFs, which
would roughly be about half of that net to our interest. We'll have to look at
the recovery at Mari-B. In our own thoughts there are some probables associated
with improved recovery there, but obviously those won't even be considered for
booking until we have performance in the reservoir.
I would just add that we had a note in our release on how we determine reserves.
Mari-B in Israel is one where we had a third-party independent engineering study
done, as well, there was one done in Equatorial Guinea and one in Ecuador.
QUESTIONER:
Okay. And just a follow-up on Mari-B, is there a number you can put to the
incremental capital costs for you that would get you to capacity for that 600?
CHUCK DAVIDSON:
Well, to get to the 600 million, let me put it this way: We have, I think, five
wells that are completed right now. And they have current deliverabilities of
some 80 to 100 million a day each. So, we have deliverability of let's call it
approaching 400 to 500 million a day. So, if we wanted to get the 600 million
24
we'd have to tie in a couple more wells, maybe a sub-sea well, to bring it in.
Which is, maybe, we're talking $25 to $30 million apiece. The bulk of our
capital in Israel has been spent. The facilities were designed to handle 600
million. We have a 30-inch pipeline that offtakes from the platform that goes to
the delivery point. So the key on Israel is the growth of the market and the
growth in our ability to access it. That's why it's such an important thing to
grow production at relatively low incremental cost, very high margin. So that's
why our focus is on additional marketing in accelerating the delivery of gas in
Israel.
QUESTIONER:
Great. Thank you.
CHUCK DAVIDSON:
Thanks.
OPERATOR:
Thank you. Your next question comes in from Questioner. Please go ahead.
QUESTIONER:
Good morning.
CHUCK DAVIDSON:
Good morning.
QUESTIONER:
I see here that in North America over half of your budget is earmarked for
exploration. And I know you've done superbly onshore, but it's been the offshore
that's been a little bit of a struggle. Even if you booked Lorien, your finding
costs would still have looked high. First, where is that exploration going to
and second, what gives you encouragement, with the exploration, that you can
begin to turn things around, particularly in the offshore?
CHUCK DAVIDSON:
Right. I think you're correct on the stats there in terms of our split.
Actually, onshore U.S. we've actually pulled back the percentage that goes into
exploration this year a little bit from what we had last year. And that's just
because we've had more development opportunities that came up, particularly in
25
the Gulf Coast where we're following up on some things. So that when we look at
our overall capital program for 2004, two-thirds is development and one-third is
exploration. In the U.S., though, we've always carried a bit higher percentage
on exploration. The exploration dollars in the Gulf of Mexico are clearly
focused on that deepwater drilling program and the deep shelf drilling program.
There is very little else that's outside that that would make our cut in our
high-grade process.
The onshore exploration program is almost totally focused along the Gulf Coast.
We've now done post-mortems on that for two years. It shows solid returns. Given
that this is flush production, low cost production from an operating cost
standpoint, we see that F&D costs are very competitive. I would also add that we
look at Lorien from a standpoint that that's a sub-sea tieback, and that the
development costs are not substantial there. We see it as an overall project
that looks like it's going to be a good return. Yes, it is higher cost, but it's
high quality flush production, high rate. It's no different than Boris. We see
Boris as being higher overall cost, but excellent return because of the
productivity of the well.
QUESTIONER:
The confidence that you have in stepping up the deepwater drilling and also
continuing with an active program on the shelf, is you've got a better sense of
how to unlock or identify those reserves to begin to bring those finding costs
down. Or is there something in particular that you feel you've got a better
grasp of that should help improve things in both of those areas or continue that
success that you've had on Lorien and Boris?
CHUCK DAVIDSON:
I think that in the case of deepwater, we really had to shake that whole
portfolio out and have completed that process. We're now focusing on the
Mississippi Canyon areas in deepwater. We're focusing more in the Green Canyon
area, the Mississippi Canyon area where we have more knowledge, there's more
infrastructure and the time between discovery and production is reduced. We just
look at our overall success rate and, as I mentioned earlier, a full 20 percent
of our production in the Gulf of Mexico is now coming from deepwater.
26
We've had good success rates on the deepwater program, especially in the last
three years as we've changed its focus. And it's also gotten the scrutiny of a
much enhanced exploration process where now each prospect has to go through a
significant review process, peer review process, risking process. So I feel more
comfortable when I see the results. I saw the results at Lorien, where our
post-drill results matched fairly closely with our pre-drill expectations. And
as we see more of that, where results match pre-drill expectations, it gives us
more confidence that what we're looking at from a program basis makes sense.
QUESTIONER:
Okay. Thank you.
CHUCK DAVIDSON:
Thank you.
OPERATOR:
Thank you. Your next question comes in from Questioner. Please go ahead.
QUESTIONER:
Good morning.
CHUCK DAVIDSON:
Good morning.
QUESTIONER:
I think most of my questions have been answered, just a couple of follow-ups.
Are the asset dispositions basically through, or do you plan any kind of further
sales in 2004?
CHUCK DAVIDSON:
Right now we have not identified any specific further sales in 2004. So we're
just finishing up that one offshore package. The nature of this business is that
we're always pruning and trimming, but 2003 was kind of a significant catch-up
for us to clean out in several areas. So, right now we have not identified
anything specific going forward. If anything, it would hopefully just be some
minor things in various areas.
27
QUESTIONER:
Okay, and I think lastly, getting back to your deep shelf play, you answered a
few questions about this. It sounds like your success rates are really what your
original objective was. What about in terms of target sizes for your reserves?
And further, do you have anything that's been on production long enough that
would give you an indication of what kind of decline curves you're looking for?
CHUCK DAVIDSON:
On the target sizes, I think that as we've improved the exploration processes,
we have moved probably the pre-drill estimates down somewhat. Before, I think
early in the program, a lot of people were thinking of target sizes of 50 to 100
Bcf. And I think the reality is there's probably more that are in the 20 to 50
Bcf range rather than 50 to 100 Bcf. And so we have seen results that tend to
work more into that latter range rather than the former range.
There's a different component to our program which is very unique to Noble, and
that is that we're in a carbonate play in the Viosca Knoll. It has a whole
different set of economics than what we talk about in terms of some of these
other deep shelf opportunities. So that for instance, while it may be below
15,000 feet, it has a different pressure regime, it has much lower drilling
costs, it has a lot of infrastructure that we and Chevron have put together. And
as a result, we see very high returns on those. That program has been underway
for a number of years. So we've got reasonable decline rates. But you can't use
it because it's out of a carbonate rather than... It's out of James Lime rather
than being out of some of the other sandstone.
In the deep shelf, I would say we've had a number of deep shelf wells, but their
decline rates run all over the map just like in other areas. I think there is
one theme, and that is that for deep shelf wells, there's probably more of a
reservoir quality issue. So that you can get tighter rock, and so you see some
different rates there. But for instance, Mound Point, we're not seeing enough
production history there to put up a decline rate. I'd say that the data is
limited.
QUESTIONER:
Fair enough. Thank you.
28
CHUCK DAVIDSON:
Thank you.
OPERATOR:
Thank you. Your next question comes in from Questioner. Please go ahead.
QUESTIONER:
Good morning.
CHUCK DAVIDSON:
Good morning.
QUESTIONER:
Two quick ones. Ironhorse, would you be willing to talk about the rates that
you're getting there, and how much they might be below what you see as a hurdle
rate for economic thresholds?
CHUCK DAVIDSON:
Well, I think the answer on that is that it all depends on what the decline rate
is. I know in visiting with our folks the rates that we have seen so far have
been below a million cubic feet a day of production. The key is what it will do
on a sustained basis into a pipeline. We have a connection there and that's why
we plan an extended testing period there. The key is ultimate reserves and that
can only be determined with this tight rock by some extended testing.
QUESTIONER:
Okay, all right. Last one. Ecuador utilization, any changes as you see them in
2004 versus 2003 on average?
CHUCK DAVIDSON:
No, we see 2004 utilization following about the same pattern and again, we have
the dry season and the wet season, but we don't really see any major
differences. We're projecting on average for the year about an 80 to 85 percent
dispatch rate. So we're probably up a little bit this year after everything sort
of settled down and the plant was running fine. I think we're comfortable that
the market has remained about the same, and we continue to have strong
electricity prices because, of course, crude oil prices in Ecuador drive their
power prices.
29
QUESTIONER:
Okay. Thanks very much.
CHUCK DAVIDSON:
Thank you.
OPERATOR:
Thank you. Your next question comes in from Questioner. Please go ahead.
QUESTIONER:
Hi guys. A couple of quick ones. You said Lorien met your pre-drill estimates,
Chuck. So, if you had booked it, what would your domestic reserve replacement
have been if you hazarded a guess?
CHUCK DAVIDSON:
The Lorien was probably on a net basis maybe be somewhere about, and I'm going
to give you a range, five to ten million barrels equivalent, net. If you, for
instance, look at the lower end of that offshore it would be about $16 a barrel.
So it has a big swing. But it's just one well.
QUESTIONER:
Okay.
CHUCK DAVIDSON:
But if, I mean, if you just want to fly through the whole domestic you can just
add that. And again if you look at it on the lower end of the range, it would
probably add another third to reserves added on the domestic, so it would cut
the overall domestic rate down proportionately.
QUESTIONER:
Okay, thanks. Two more quick ones. You already have production capacity on gas
in Ecuador. So why are you drilling more wells? Are you going to ramp up your
power generation there, or are you contemplating that?
CHUCK DAVIDSON:
What we did was, when we did the initial drilling program in Ecuador, we drilled
a few wells. We basically had enough supply that would last us, I think our
30
estimate now is before deliverability would become a factor, it would carry us
into at least through this year and maybe 2005. But what we didn't want to do
is, until we saw how the power market worked -- payments, all those pieces -- we
didn't want to overdrill the field. And we had had drilling problems early on
which we wanted to make sure that we had studied on a little bit before we threw
a lot of money at these wells. So we drilled enough to give us a few years of
deliverability with a plan that we bring the rig back and develop additional
capacity. And this time we expect that capacity would last us really well beyond
2010.
QUESTIONER:
Okay, and then the last one for me - what about more activity in the North Sea
or the acquisitions market? How aggressive are you looking at both?
CHUCK DAVIDSON:
On the activity side in the North Sea, I didn't mention, we have a discovery
that we had last year. We've actually gone back and done some appraisal
drilling. We had that project that's looking like we'll work to see if we can't
sanction it this year. That's the plan at least. We don't have booked reserves
there. We continue to look at acquisition opportunities in the North Sea.
Perhaps not as many came about in 2003 as what the industry had been
anticipating. It's an area that we're interested in, but we have had better
success in the North Sea in acquiring either discoveries that have been
undeveloped or some new opportunities, rather than just buying old fields.
And so we've been careful not to pursue some of the options that get involved in
old fields with some very high operating costs, with others who own the
infrastructure and with very high abandonment costs. But there seems to be still
quite a few opportunities there, undeveloped discoveries that we're hopeful will
be turned loose. We maintain a group there to not only manage our operations, or
the non-operated production we have there, but also look at additional
acquisition opportunities.
QUESTIONER:
Thanks, Chuck.
CHUCK DAVIDSON:
Thank you.
31
OPERATOR:
Thank you. Your next question comes in from Questioner. Please go ahead.
QUESTIONER:
I'm afraid most of my questions have been answered, but one quick one. Chuck, in
your mind what is a reasonable finding and development cost that you're looking
at for the Gulf of Mexico in aggregate?
CHUCK DAVIDSON:
Well, I think, in aggregate, if it includes a sizeable portion of near-term
production, I'm going to say deepwater that is sub-sea tieback so it comes on
production in one to two years, or shelf production that is flowing back... deep
shelf production that is flowing back quickly. Using, I would say, modest price
curves, not the high prices that we're doing now, you can still see things that
make sense, even all the way up to $2 an Mcf which is $12 a barrel. You'll get
higher rates of return that generate in excess of your cost of capital. That to
me, in today's world, with flush production, with oil prices above $20 a barrel
and gas prices of maybe $3.50, that you can make it work. I think as you go
above that, you have to really start looking at the individual projects pretty
carefully.
QUESTIONER:
Thank you.
OPERATOR:
Thank you. Your next question comes in from Questioner. Please go ahead.
QUESTIONER:
Good morning, gentlemen. I guess a lot of my questions have been answered. But a
couple of little things to fill in a few blanks. The 160 Bs, I guess, that you
added internationally, can you give me a breakdown of where they came from?
CHUCK DAVIDSON:
I'll kind of give you a cross-section of some of the areas in the North Sea in a
couple of our projects there, for instance Hanze had significantly performed
better and as a result we had reserve additions there. While most of our capital
32
went towards EG, Equatorial Guinea, towards developing our big projects, we did
have some reserve additions in Equatorial Guinea that brought reserves up there.
And some of it had to do with just some gas reserves, that we didn't have booked
before, that go to the methanol plant there. And it was kind of scattered after
that. We didn't add any reserves, of course, in Israel. And we didn't add any
reserves, of course, in Ecuador. And I think we ended up shy of just about flat.
So it was basically Equatorial Guinea and North Sea.
QUESTIONER:
Okay. All right, great. And then on the mechanical side, I was wondering if you
could just break down that other international category in terms of volumes and
pricing. I know in China, I think you said you did 3,300 barrels net.
GREG PANAGOS:
Yes. Other international, we have 3,300 barrels a day in China. The remaining
liquid volumes would be Argentina.
QUESTIONER:
Okay.
GREG PANAGOS:
Then we have natural gas that is really split between Argentina and Ecuador. And
Argentina is a very small part of that. The Equador volumes for the fourth
quarter were 26 million cubic feet per day as detailed in the AMPCO/Ecuador
schedule at the back of the press release. So you just have to take the
difference. And the difference is Argentina.
QUESTIONER:
Okay. And then what was your hedging impact for the fourth quarter on gas, just
total company?
JAMES MCELVANY:
It was eight cents with the gas.
QUESTIONER:
That's a negative eight cents or positive?
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JAMES MCELVANY:
Yes, negative eight cents. It was eight cents, and was a negative 75 cents for
crude.
CHUCK DAVIDSON:
75 cents a barrel negative for crude in the fourth quarter.
QUESTIONER:
Okay, great. And then just one more question mechanically. Your U.S. severance
tax, what was that?
CHUCK DAVIDSON:
I think I'll have to get back to you on that one.
QUESTIONER:
Okay. Great. Thanks a lot.
CHUCK DAVIDSON:
Thank you.
OPERATOR:
Thank you. Your next question comes in from Questioner. Please go ahead.
QUESTIONER:
Good morning. A couple of quick questions. As most of your capital spending
program is over international projects, you indicated that your cash flow
generation is going to exceed your capital needs. What would be the logic of
placement of the cash flow?
CHUCK DAVIDSON:
We kind of have several alternatives we're looking at, one that has kind of
already been underway. As we had been developing the international projects, we
had pushed our debt up a bit. And so, initially, we've been allowing some of the
excess cash flow to reduce debt because we just kind of went through this past
quarter with a period when international actually started generating cash flow
in excess of its capital needs. So the first step was we're allowing some of our
debt to come down. We've been, from a long-term basis, targeting debt-to-
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book cap somewhere around the low 40s. At very high commodity prices, it might
even go below that.
The next area, which I think is very dependant on timing and pricing and market
values, is, again, we don't include any acquisitions in our capital budget, but
we have really, starting about a year ago, started putting in place a process
and a group that is looking at opportunities here domestically or
internationally. If they're here domestically, they're likely to be onshore and
in some of the longer-life gas basins. Or, as we had responded to one question
earlier, we're looking at places for instance like the North Sea. And quite
honestly, when we looked at the U.S. so far, those have been very expensive, so
we haven't acquired any. But that's all part of a cycle and we'll be
opportunistic. And we may see something that fits and that would be a place
where additional capital would be expended.
Also, we continue to look and identify new international ventures that, again,
we don't have them carried in our budget but we're constantly evaluating new
opportunities that could lead to major programs down the road. We see that as a
possible alternative for cash. Going beyond that, if you look at these high
commodity prices, we obviously know that there are other options, including
stock repurchases down the road if that looks like the best option versus let's
say acquiring other projects or investing in new developments. And so we really
look at all three pieces, but the bottom line is in the capital program. We lay
out basically only for the base drilling program we've identified, and all the
incremental opportunities would be added to that.
QUESTIONER:
You mentioned too high F&D costs. What would be a realistic F&D cost and the
realistic oil and gas prices?
CHUCK DAVIDSON:
I think when you look at domestic, and it all depends on what the view is of
realistic oil and gas prices, but I keep getting back to something on a
gas-equivalent basis of below... this is all-in now, this is onshore and
offshore, below $1.50. And it could be even much lower than that depending upon
depending upon the area. Now an earlier question was about the Gulf of Mexico.
And I think Gulf of Mexico could be as high as $2 an MCF because of flush
production there. But
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not for deepwater projects that take five years to come on stream. They cannot
be anywhere near that.
QUESTIONER:
And you don't see right now any opportunities that you can buy reserves for less
than that?
CHUCK DAVIDSON:
I think it's right on the borderline. We have seen recent acquisitions announced
that are right at $1.50 an Mcf, or maybe even a little bit above $1.50 an Mcf.
So they're right on the threshold and, unfortunately, some of those might be
some longer-life reserves. Or they might require additional capital to develop,
which would push the ultimate full-life FD&A costs above that.
QUESTIONER:
Okay, thank you.
CHUCK DAVIDSON:
Thank you.
OPERATOR:
Thank you. Your next question comes in from Questioner. Please go ahead.
QUESTIONER:
Good morning, guys. I wonder if we can get back to some of the regional volume
breakdowns. You know, we've got enough information I think to layer in Israel,
Ecuador, EG. What are you looking for in volumes out of the U.S., the U.K. and
international? Should we just assume your best efforts are to keep those areas
flat?
CHUCK DAVIDSON:
I think in terms of U.S. domestic we feel very comfortable that for 2004 we'll
see, and again, let's keep it on continuing operations so we don't get caught up
in discontinued operations, that a flat volume profile on there is very
reasonable for us. I think in terms of U.K., I think that our thoughts are we're
going to see some natural decline there. Hanze has been producing very well, but
we expect it to go on a decline some this year. And then we have this Donan
discovery that
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we'll be developing, that will be my guess is 2005, which would kick up
production there. So this year some decline in U.K., kind of just a natural
decline, not a specific decline. We just have to watch Hanze very carefully
because it's a high rate property.
QUESTIONER:
And other international?
CHUCK DAVIDSON:
China is flat. This year we're doing a little bit of drilling. I think the last
report you saw with China on a gross basis was a little above 7,000 barrels a
day. And then of course EG and Israel are growing. So on the international side
probably the one area that's probably got more decline to it than the others is
the North Sea area, and all the other areas kind of fit the model. As we said,
they're more longer life in production, they're more stable. So we're not
fighting decline rates on those.
QUESTIONER:
Getting back to the take-or-pay, do you have a high degree of confidence you'll
actually get paid on that? I mean if you look at take-or-pays in other parts of
the world and granted, they may not be Israel-type business practices, but
oftentimes it's hard to actually get that money out of the companies.
CHUCK DAVIDSON:
I think we have a very high degree of confidence that our purchaser will honor
the contract.
QUESTIONER:
Okay. And what about the new contract that you mentioned that you have agreement
on? What kind of volumes are you talking about?
CHUCK DAVIDSON:
It's with a refinery. It's relatively small amounts, maybe 10 to 15 million
cubic feet a day, something like that, but it's a small amount, and we will see
additional customers in the area. That's kind of just an easy add-on because
they're literally across the fence from the power plant.
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QUESTIONER:
Okay.
CHUCK DAVIDSON:
The big ones that we need to go after this year are the larger industrial
customers, independent power producers. We've got a candidate there, as well as
Israeli Electric is a candidate there. So those are the big targets for 2004.
QUESTIONER:
Right. And then, again I hate to go back to something that's been covered quite
robustly, but with regards to Ironhorse, I know you need to watch performance
there, but do you have any plans to drill more this year in the current budget?
CHUCK DAVIDSON:
I'll put it this way: We have not approved any additional drilling with our
partner there. We've both said that it's going to be dependant on the evaluation
as well. So we have not approved anything, and we can accommodate it in our
budget absolutely.
QUESTIONER:
Okay. And then one final, thing. Can you just help me get my hands around the
F&D number that you reported. And if you start blending it into three and
five-year averages, it basically points to the fact that your DD&A should be
actually rising, rather than what you've given in terms of 2004 guidance coming
down. And I wonder if you could just kind of just help explain that.
CHUCK DAVIDSON:
I'm stumped on that one because we've looked at it on a total company basis, as
we bring in the international reserves that are very long-life and have low DD&A
rates, it actually brings it down. And as James noted, the impairment alone at
East Cameron 338 that is a fairly short-life property that would have been
generating a lot of DD&A has been generating a lot of DD&A. It was a high DD&A,
high completion rate property even before the impairment. I think that the drop
we see alone from that is about 75 cents a barrel equivalent for 2004.
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QUESTIONER:
Right. Yeah, okay, that might explain it.
CHUCK DAVIDSON:
Those are always just pay now or pay later, and for Gulf of Mexico properties
that are shorter lived it comes back and you recoup it very quickly.
QUESTIONER:
Yes.
GREG PANAGOS:
Another contributing factor to that would be property sales, some of which had
higher DD&A rates than the company average.
QUESTIONER:
Right.
CHUCK DAVIDSON:
That's absolutely right.
QUESTIONER:
Okay, Thanks a lot.
CHUCK DAVIDSON:
Thank you.
OPERATOR:
Thank you. Your next question comes in from Questioner. Please go ahead.
QUESTIONER:
Hi, guys. With regard to the production guidance that you've given, and I
realize that most of your exploration work has long lead times, but is there any
exploration success built into the 2004 number?
CHUCK DAVIDSON:
We have tended in this guidance, in the divisions as they looked at their
exploration program, to not factor in much for exploration success. Now that
might be a little conservative, but usually what happens is when you get caught
39
up in that you get over optimistic on when wells will come on and when you get
results. So for instance, I would tell you there is nothing in the international
budget for exploration success. There is some for onshore because they get wells
on quickly and it's a more ongoing program. They would factor in what we would
call an exploration wedge that broadens out a little bit in the latter part of
the year, and they factored in timing estimates for wells. Offshore it gets more
difficult. For instance, even though we would expect to appraise Lorien, we
wouldn't factor it in. We're getting ready to drill another deep shelf well at
Mound Point. Even though theoretically it would be down it really is not going
to contribute to their production this year, at least we wouldn't include it in
our guidance. Let's put it that way.
QUESTIONER:
Okay. And offshore on the extended wells that you have ongoing, is that a
stimulation target there? Could you do something to raise the rates on that
well?
CHUCK DAVIDSON:
On the onshore well?
QUESTIONER:
No, offshore.
CHUCK DAVIDSON:
Well, we've got one that we're producing at Mound Point.
QUESTIONER:
Right.
CHUCK DAVIDSON:
And it's producing. This is one well producing about 34 million a day
equivalent.
QUESTIONER:
I'm sorry, I thought you had one that was a million a day.
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CHUCK DAVIDSON:
That was onshore. That's the Ironhorse. And we have done some stimulation work
on that, and that's what we're evaluating.
QUESTIONER:
Okay.
CHUCK DAVIDSON:
You're on target.
QUESTIONER:
All right. Thank you, Chuck.
CHUCK DAVIDSON:
Thank you.
OPERATOR:
Thank you. Once again, if there are any questions please press star one on your
touchtone phone. Sir, there are no questions at this time.
GREG PANAGOS:
Thank you all for listening. And if you have any more questions, please feel
free to give me a call.
OPERATOR:
Thank you very much. That concludes today's conference call. Please disconnect
your lines and have a wonderful day.
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