Filed by Noble Energy, Inc.
(Commission File No. 001-07964)

Pursuant to Rule 425 under the Securities
Act of 1933 and deemed filed pursuant to
Rule 14a-12 of the Securities Exchange Act
of 1934

Subject Company:
Patina Oil & Gas Corporation
(Commission File No. 001-14344)

A webcast of the Noble Energy, Inc. fourth quarter and full year 2004 earnings conference call was held on February 22, 2005. A transcript from that call is provided below.

Safe Harbor Statement
This transcript 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. Important factors that could cause the actual results to differ materially from those projected include, without limitation, the volatility in commodity prices for oil and gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, competition, government regulation or other action, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy’s business that are detailed in its Securities and Exchange Commission (“SEC”) filings.

Additional Information
In connection with the proposed merger (the “Merger”), Noble Energy and Patina Oil & Gas Corporation (“Patina”) filed with the SEC on January 25, 2005, a joint proxy statement/prospectus on Form S-4 that contains important information about the Merger. These materials are not yet final and will be amended. Investors and security holders of Noble Energy and Patina are urged to read the joint proxy statement/prospectus filed, and any other relevant materials filed by Noble Energy or Patina because they contain, or will contain, important information about Noble Energy, Patina and the Merger. The preliminary materials filed on January 25, 2005, the definitive versions of these materials and other relevant materials (when they become available) and any other documents filed by Noble Energy or Patina with the SEC, may be obtained for free at the SEC’s website at www.sec.gov. In addition, the documents filed with the SEC by Noble Energy may be obtained free of charge from Noble Energy’s website at www.nobleenergyinc.com. The documents filed with the SEC by Patina may be obtained free of charge from Patina’s website at www.patinaoil.com.

Noble Energy, Patina and their respective executive officers and directors may be deemed to be participants in the solicitation of proxies from the stockholders of Noble Energy and Patina in favor of the Merger. Information about the executive officers and directors of Noble Energy and their ownership of Noble Energy common stock is set forth in the proxy statement for Noble Energy’s 2004 Annual Meeting of Stockholders, which was filed with the SEC on March 24, 2004. Information about the executive officers and directors of Patina and their ownership of Patina common stock is set forth in the proxy statement for Patina’s 2004 Annual Meeting of Stockholders, which was filed with the SEC in April 2004. Investors and security holders may obtain more detailed information regarding the direct and indirect interests of Noble Energy, Patina and their respective executive officers and directors in the Merger by reading the joint proxy statement/prospectus regarding the Merger, which is included in the Registration Statement on Form S-4 filed by Noble Energy with the SEC on January 25, 2005.

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NOBLE ENERGY
CONFERENCE CALL FOR FEBRUARY 22, 2005 @ 10:00 A.M. EST
CHAIRPERSON: GREG PANAGOS
EMAIL TRANSCRIPTION TO: jpippenger@nobleenergyinc.com

Operator: Good morning ladies and gentlemen. Welcome to the Noble Energy 2004 Fourth Quarter and Full Year End conference call. As a reminder, this conference 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 2004 earnings conference call. I’m Greg Panagos, director of investor relations. With me this morning are Chuck Davidson, our chairman and CEO, and Chris Tong, our CFO. Today we’ll be going over Noble Energy’s fourth quarter results. Chris will go over our 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’d also like to point out that, in the course of our discussion this morning, we are likely to refer to certain measures such as discretionary cash flow. While these are not generally accepted accounting principles measures of financial performance, we believe they are good tools for internal use and for the investment community in evaluating the company’s overall performance. We have provided a reconciliation of these non-GAAP measures on our web site.

     Also, in connection with the proposed merger between Noble Energy and Patina Oil & Gas, on January 25, 2005 we filed a joint proxy statement/prospectus on form S-4 that contains important information about the merger. Those materials are not yet final and will be amended. We urge you to read the joint proxy statement/prospectus and any other relevant materials we may file because they contain, or will contain, important information about Noble Energy, Patina and the merger.

     As many of you already know, James McElvany will be retiring soon after 26 years of service with the company. I think I speak for everyone at Noble Energy, and all of you participating in the call, in saying that James has made an enormous contribution to the company, and we will all miss him. I’ve had the pleasure of working with Chris Tong for about two months now, and I think you’ll find Chris to be knowledgeable, helpful and pleasant to work with. And with that I’ll turn the call over to Chris to discuss our financial results. Chris?

Chris Tong: Thank you, Greg, and good morning ladies and gentlemen. As has been the case all year, the fourth quarter was strong for Noble Energy. We continue to see solid improvement in all of our key value drivers, and we expect our momentum to continue. Production from our international projects is still ramping up and we are close to adding significant new production in the deepwater. Fourth quarter production was up from the third quarter despite losing 3,500 barrels per day from the continued shut in of Main Pass 305 and 306.

     Once again our financial results were solid, setting new records for both income and cash flow. Noble Energy reported fourth quarter net income of $87.4 million, or $1.48 per share, compared to net income of $83.7 million, or $1.43 per share, for the third quarter. Discretionary cash flow for the fourth quarter ‘04 was $191.6 million.

     Reported net income included $8.5 million after tax of one-time non-cash charges related to the impairment of domestic oil and gas assets, the recognition of certain estimated future insurance premiums based on prior loss

experience and a gain for the asset exchange in the North Sea. Excluding the after-tax impact of these charges, Noble Energy’s fourth quarter income would have been $95.9 million or $1.63 per share.

     Looking at a segment reporting schedule by country, reported domestic operating income from continuing operations was $69.3 million for the fourth quarter 2004 compared to $75.7 million in the third quarter. Included in domestic operating income was $9.9 million of asset impairments. Adding back those impairments would result in operating income of $79.2 million, a 5% increase over the third quarter.

     Revenue was about $13 million higher this quarter compared to last due to higher realized commodity gas prices and slightly higher production, partially offset by slightly higher expenses and slightly lower other income. Higher unit lease operating expense was a result of increased work over expense and the insurance accrual. Higher SG&A was a result of an increase in the short-term incentive bonus plan, higher audit and Sarbanes-Oxley compliance related fees.

     Excluding the gain on the like-kind asset exchange in the North Sea, international operating income increased $20 million, to $95 million, compared to the third quarter. The increase in international results occurred in every region with the exception of Israel. Operating income in Israel was down slightly, about $4 million. As we indicated in the third quarter earnings press release, natural gas sales in Israel are dependent upon seasonal demand and we expected fourth quarter volumes to decline compared to the third quarter due to reduced electricity demand.

     Equatorial Guinea was a real bright spot with operating income of $56 million, $18 million higher than last quarter. LPG, natural gas and condensate sales accounted for about $7 million of the increase, nearly all of which was due to ramp up in condensate volumes from Phase 2A. Methanol prices remained at near historic highs and were flat with the third quarter, but volumes increased over 4 million gallons. Leaving out the impact of other income, methanol generated $7 million more in operating income than last quarter because of higher sales volumes and lower costs of goods manufactured.

     Our North Sea operations accounted for $4 million of the increase, excluding the gain of $4 million on the like kind exchange. Higher natural gas prices and lower exploration expense accounted for the improvement.

     In Ecuador, operating income increased $5 million as we moved into the dry season, reflecting a 107% increase in power production and a 31% increase in power prices. Slightly higher expenses across the board in China and Argentina totaled approximately $3 million.

     The current strong commodity price environment, along with the rapid growth coming from international operations and our improved domestic business, continued to help us strengthen our balance sheet significantly. Total debt-to-book capitalization at the end of the third quarter declined again to 37.5% compared to 46.4% at the end of 2003. Net debt-to-book to capitalization at the end of the fourth quarter was down to 33%.

     Turning to Noble Energy’s hedges for 2005, we have about 80 million cubic feet per day of natural gas hedged with an average floor of just over $5.00 per Mcf and an average ceiling of over $7.80 per Mcf. On the crude side, we have hedged an average of approximately 20,500 barrels per day with an average floor of nearly $32.20 and an average ceiling over $43.30. For 2006, we have hedged very small amounts, 14 million cubic feet per day in the first quarter of 2006 with a floor of $5.00 per Mcf and a ceiling of $8.00 per Mcf. In the first half of 2006, we have hedged 1,900 barrels of oil per day at a floor of $29.00 per barrel and a ceiling of $35.07 per barrel.

     In addition to the hedges I just described, we’ve also placed swaps against Noble Energy volumes in anticipation of the merger with Patina. For May through December 2005, we have sold forward nearly 13,100 barrels of oil per day at $39.62 per barrel and 100 million cubic feet per day of natural gas at $6.60 per Mcf. For 2006 through 2008, we have sold forward 150 million cubic feet of gas at average prices of $6.40 in 2006, $5.96 in 2007 and $5.60 in 2008. On the crude side we have daily volumes swapped of 16,600 barrels at $40.47 in 2006, 17,100 barrels at $39.19 in ‘07 and 16,500 barrels at $38.23 in 2008.

     As most of you have probably seen, we put out a press release in January providing guidance for 2005. That guidance remains unchanged; so, I won’t take your time going over it again. And with that let me turn the call over to Chuck.

Chuck Davidson: Thank you, Chris, and good morning everybody. This is Chris’s first earnings call with us, and I certainly want to add how excited we are to have him as part of the Noble Energy team. And I also want to echo Greg’s opening comments in that we all wish James McElvany and his family the best as he enters retirement shortly. He’s done an outstanding job for us and certainly leaves things in good shape. I’d also add that it’s been a really nice transition to have two experienced CFO’s working through a number of important issues the past few months.

     Without question 2004 was a very important year for Noble Energy. We accomplished a great deal, and the results show it, including: 16% growth in production from our continuing operations, 15% growth in reserves, a record earnings of $329 million and record discretionary cash flow of $809 million. Chris talked about how our balance sheet has improved. Also, we began in 2004 gas sales in Israel, and we saw continuing growth in production in Equatorial Guinea as a result of the projects there.

     On the domestic side, we see three important deepwater projects that are moving towards development that will add significant new production this year as well as next. And then finally, we announced the merger, proposed merger, with Patina Oil & Gas in December.

     Today I’m going to focus my remarks on Noble Energy’s results and current activities and would refer investors to the S-4 and related filings that Greg mentioned at the opening of the call for information on the transaction with Patina. We do remain very excited as to the potential of the combined companies and, as previously announced, we still expect the merger with Patina will close approximately mid-April. But, obviously, the final schedule will depend on receiving all necessary regulatory and shareholder approvals.

     Starting out and talking about reserve replacement, we certainly had one of our best years in several. We replaced 297% of 2004’s production from continuing operations, and that includes all sources but excludes sales. We added 116 million barrels of oil equivalent of reserves with associated exploration, development and acquisition costs of $661 million. What I believe is especially notable is that on the domestic side we added over 37 million barrels equivalent, which represented 164% production replacement. Just as important, this past year both the onshore and offshore areas more than replaced their production.

     New reserves for our Lorien deepwater development were not included in the 2004 additions. The Lorien schedule was always tight, and with operational delays we encountered late in the year with Hurricane Ivan we decided not to push the booking. But obviously Lorien will give us a nice start for reserves in 2005.

     So we enter 2005 coming off a very strong year, but also a transformational year. Transformational in the sense that the major international projects show rapidly growing production with, of course, less capital requirements and a domestic program that has expanded with greater focus and much improved results. Speaking operationally, production volumes are just about where we would expect them to be at this point and, for that reason, we reaffirmed a few weeks ago our 2005 production growth guidance of 10% over 2004.

     Our capital spending for 2004 was a bit lower than we were expecting, although certainly higher than our original budget. And hindsight says we were probably a bit too aggressive in scheduling the timing on some 2004 capital commitments, particularly in the deepwater. But this has been accounted for in our 2005 capital budget of $735 million. Two-thirds of that will be going towards domestic projects with the remaining one third to international. Of the domestic spending, approximately $170 million will go for deepwater developments.

     Overall, the development/exploration split for 2005 is 70%/30%, and I’ll talk a little bit more about our 2005 program in a few minutes. I’d also like to add that Noble Energy did a good job of maintaining discipline and controlling both cash as well as non-cash costs in what we certainly see as an inflationary environment. Our unit lease operating expenses excluding workovers increased by only $0.17 per barrel of oil equivalent from 2003 to 2004, approximately a 5% increase. Unit SG&A cost declined by $0.04 per barrel equivalent or roughly 3%. And

DD&A declined by $1.28 a barrel or approximately 14%. These excellent results were the result of, certainly, a lot of focus on costs as well as the benefit of the growing percentage of lower cost international production that we’re seeing.

     Fourth quarter production of 106,000 barrels of oil equivalent per day was in the upper part of the guidance we gave you in October, and compared to a little over 104,000 for the third quarter. This increase in production primarily resulted from the continued ramp-up in Phase 2A of Equatorial Guinea, and was due to some increased production in the fourth quarter in the North Sea after some seasonal slowdowns previously, as well as a pick-up in volumes in Ecuador as we get into the dry season there where we generate higher levels of power.

     Reported production volumes for the year increased 16% to just under 107,000 barrels of oil equivalent per day, and that’s up from around 92,000 in 2003. All these numbers are on a continuing operations basis.

     Domestic volumes were up 2,300 barrels per day. And of course, as we noted earlier, international volumes were up primarily because of Equatorial Guinea and, of course, the first year of operations for Israel.

     Kind of going through some of our key areas, I’ll start with the domestic onshore area. We’ve accelerated our activity onshore U.S. And during this past year we drilled and statused onshore about 111 gross exploration and development wells, of which about 94 were successful, for an overall success rate of 85%. Approximately 34 of these wells were drilled in the Gulf Coast region. And currently our domestic business is very active, and really throughout the area of domestic onshore we are currently seeing about 20 wells that are in various stages of drilling or completion.

     In 2005, we expect to drill around 36 wells in the Gulf Coast area. A little less than half of these will be in the Aspect AMI area. Another six will be in the very successful Duval County area where we went seven for nine in 2004. During 2005, we should also be seeing the benefits of some of the work we’ve been doing in some of the deeper areas, deeper from a regional basis in the Gulf Coast. We’ll be, our plans are to drill at least two deep tests in the Gulf Coast area. One will be South Lake Arthur, and another, potentially, is our Mitchell Bayou prospect. Both are in south Louisiana. South Lake Arthur may start drilling in the May time frame, and it’s a 20,000-foot miogyp marg test. While Mitchell Bayou is around 19,000 feet. It’s a miogyp test as well, and it will be perhaps starting around midyear. Both of these are very large prospects, certainly in the 50 plus Bcf range with upsides well beyond around 100 Bcf and we’ll be operating both of those.

     The Mid-continent and Rocky Mountain region was more active in 2004 than it has been in several years, and we’ll see even greater activity in 2005. Last year in the region we drilled 77 wells, of which 69 were successful. But I would say that that activity will pale in comparison to what we expect and have already begun in 2005.

     This year we expect to drill over 200 wells in the Niobrara, which is in Colorado. Currently three rigs are running there, two operated by ourselves and one by a partner. We also expect to drill 40 additional wells in the Bowdoin field in Montana, about 25 or so wells in the Piceance Basin, four to nine wells in Siberia Ridge, perhaps another two to three wells in the Iron Horse area and perhaps a total of around 15 wells in the Permian Basin. In summary, a very active program overall in all the areas in the onshore U.S.

     Turning to the offshore in the Gulf of Mexico, our investment there has, is, clearly focused on the deepwater where we’ve been paying primary attention to three deepwater developments: Ticonderoga, Lorien and Swordfish. All three are proceeding ahead. Just as a reminder, we have a 60% working interest in Lorien and Swordfish and a 50% interest in Ticonderoga.

     First up will be Swordfish. All drilling is complete, and we expect first production in this next quarter. Swordfish is a three well development, and we expect the initial net rate to Noble Energy to be around 10,000 barrels of oil equivalent per day. Obviously a sizeable development, significant impact on our production this year.

     We’re also making good progress at Lorien, although I mentioned earlier that we were delayed a bit last year due to Hurricane Ivan interrupting some operations and some delays at the end of the year. We did carry out a

successful sidetrack to the discovery well last year, and we currently have a second well that’s drilling. Lorien is planned to be a two well sub sea development with initial production of around 12,000 barrels of oil equivalent net to Noble Energy.

     We’ve now moved the scheduled start up. It was originally the very end of this year, late December. We’ve moved it to the beginning of the, early in, the second quarter of the next year. That’s to both accommodate some of the delays we saw early on, but also to accommodate some logistical requirements on the host platform and the latest estimate we’ve got on some delivery of critical components for the project.

     Ticonderoga, which was announced as a discovery in April of 2004, will be a two well development with both wells, of course, flowing back to the Kerr-McGee Constitution spar. And the production is still expected to be on mid-2006 at some 10,000 to 12,000 barrels of oil equivalent, net to Noble Energy.

     So, right now, as we switch and look at our exploration plans for 2005 in the deepwater, we’re looking at perhaps a four well program with at least two wells operated by Noble Energy. Almost all of our exploration wells for this year will be in core areas in Green Canyon and Mississippi Canyon. The first two are likely to be Little Burn, which is in Green Canyon 238. It’s a block that we picked up last year and it’s an offset to our Boris field. And the second is likely to be Slam Deep, which is in Mississippi Canyon 893. We have a 40% interest in Little Burn, which is operated by BHP. It should spud probably next month. While it’s a smaller prospect, it’s very attractive since it’s actually going to be drilled directly adjacent to the existing sub-sea system that will allow production if successful. And the Slam Deep, where we have a 34% interest, it’s anticipated that it’s most likely to follow our Lorien drilling, which would probably put it in the May/June time frame for spud there as well. It’s in the Mars basin and, again, will probably not be decisioned till the third quarter. And then there’s several candidates for drilling later in the year, all being in the Mississippi Canyon and Green Canyon areas.

     Moving over to the shelf, one of our focus areas on the shelf has been in the Viosca Knoll area, primarily in recent years in the James Lime. But right now we’re currently participating in what I think is a very interesting and very large test called Cadillac. It’s Chevron-Texaco operated. It’s in Viosca Knoll 251, and we have a 20% working interest. And at last count there were six companies participating in this test. It’s a well that’s planned to a total depth of 25,000 feet. Again, it will be testing the Cotton Valley section. Covers multiple blocks, certainly with a P50 resource potential of several hundred Bcf.

     On our program, we have moved a rig into the Viosca Knoll area where we have plans to operate one development sidetrack and then we’re going to follow up with perhaps three or four exploration wells into the James Lime. This is an area that we have been very successful. In the past we have participated primarily with Chevron-Texaco on this but, really again beginning last year, we acquired a number of prospects on our own. And so we have several of those that are in the queue. Most of them are in the 20 to 40 bcf equivalent size, although there is one that’s a bit larger than that. We find this to be a very attractive area because of the lower dry hole cost. Even though these wells are around 14-15,000 feet, we’re seeing dry hole costs of $4 million. So it’s very attractive economics.

     Moving to international, again we experienced another very strong quarter. Operating income of over $95 million, that excludes the $4 million gain on the like-kind exchange transaction in the North Sea. As you would expect, Equatorial Guinea continued to be our biggest contributor in the fourth quarter. LPG and condensate operations and methanol combined added $56 million in operating income. That’s up $18 million over the third quarter. Production was up noticeably from the third quarter, about 4,500 barrels of oil equivalent a day, again because of the ramp-up in Equatorial Guinea.

     It was also another outstanding quarter for AMPCO methanol operations and a record year as well for methanol. Full-year methanol sales volumes totaled 147 million gallons or, if you think like I do in barrels per day, that averaged out to be just over 9,500 barrels per day net sales for Noble Energy. We had an average sales price for the year of $0.69 a gallon. Clearly very strong prices. And if you kind of go through and look at 2004 versus 2003, you can get an idea of why we saw it was such an outstanding year. When you look at the comparisons, in 2004 methanol sales volumes were up 20% over 2003. Total revenue was up 34%, while costs were only up 6%

year-over-year. So obviously our margin significantly expanded, and we continue to see strong methanol prices as we enter into 2005.

     The second phase, Phase 2B in Equatorial Guinea, is scheduled to start up late during this next quarter. It’s expected to add around 6,500 barrels a day of production net to Noble Energy’s interest. And to date we’ve got all major equipment installed, a lot of the construction is complete, commissioning is beginning. In February, we did experience some reduced production due to construction in the field and some other commissioning events, but we’re now seeing the field return back to normal production.

     We’re in the process also of securing a rig for our exploration work in Block “O” and we currently expect that drilling could begin either late second or early third quarter. And again our plans this year are for two wells in Block “O”.

     As I mentioned last quarter, net production in Israel experienced a slight seasonal decline with production net to Noble Energy of just over 60,000 million cubic feet per day for the fourth quarter. We would expect that sales will continue near this rate really through the second quarter. And then, beginning in the third quarter, we’ll see increased seasonal demand and also some new infrastructure that’s available that will likely increase natural gas demand in the third quarter. Also, by that time there’ll be a natural gas pipeline up to the Reading plant in Tel Aviv. And also there, they’re converting two of its thermal units, to be converted so they can burn natural gas. And then at Ashdod they’re in the process of upgrading a gas turbine generator to combine cycle which, when complete, we would expect there to be a higher utilization of gas there as that unit is likely to be converted from just peaking use to perhaps base load use.

     Looking forward, we have a number of opportunities on marketing additional gas. We’ve mentioned in the past an agreement with a refinery there in Ashdod, small incremental volumes, 8 to 10 million. But clearly one of our top priorities this year will be to finalize some of these other marketing contracts and potential outlets that we’ve seen, including a desalinization plant and discussions still underway with an independent power producer, as well as a paper mill. So it’s, again, it’s been a very exciting year as our first year of operation in Israel. And we look for continued growth in sales in Israel in 2005 and 2006.

     For the year our Machala power plant in Ecuador generated revenues of just under $60 million, with operating cash flow of over $30 million. The power plant had operating income of just over four and a half million during the fourth quarter and operating cash flow of nearly $9 million, producing 201,000 megawatts of power at a very strong price of around $0.10 per kilowatt hour.

     For the fourth quarter, we produced just under 23 million cubic feet per day of gas from the Amistad field. And you can see that because of the seasonal nature of power generation, in Ecuador gas volumes nearly doubled compared with the third quarter which was at the 11.6 million cubic feet per day.

     In the North Sea, operating income rose to $23 million from $15 million in the third quarter. The increase in operating income was due to higher natural gas prices and, of course also, the gain on the like-kind exchange and also lower overall operating costs. We completed another successful appraisal well at Dumbarton last year and as such we expect to sanction this project probably by mid-year. We have a 30% interest in Dumbarton. I think with that it would be appropriate if we opened the line up for questions.

Operator: Thank you. We will now begin the question and answer session. To place yourself into the question queue please press *1 on your touch-tone phone. If you’re using a speakerphone please pick up your handset and then press the *1. If your question has been answered and you would like to withdraw your request you may do so by pressing *2. Please go ahead if you have any questions. Thank you, your first question comes in from Brian Singer, please go ahead.

Brian Singer: Good morning.

Chuck Davidson: Good morning.

Brian Singer: I wanted to follow up on your comments on Israel with the potential for incremental demand, new pipeline, conversion of turbines, or conversion of power plants to gas fired, desalinization plants, etcetera. Could you try and quantify what that could mean in terms of additional production going in the longer term, and then would you have to sign a take-or-pay contract, and how far in advance would you have to sign those?

Chuck Davidson: Well I think of course if you keep in mind where we started, and just as a reminder, when we look at full year of 2004, we averaged about 48 million a day of gas sales. And we would expect that this year our average for the year would be probably slightly above what the original contract was, which was about 70 million a day. So our, we would expect that this year we’d be probably in the 70 to 80 million a day average range.

     When we go to 2006, it’s a little more problematic. We do see that there’s significant take volumes up at Tel Aviv, and again it will be seasonal up there. But again, there’s about two units, so that puts it at about oh, half of what we’re seeing in Ashdod as potential incremental demand there. So just quickly doing the math, you know maybe you see another net 30 to 40 million a day as a result of that. I think when you start getting out into, and I gave those all in net, so excuse me, I’m going to switch to gross here for a minute, but keep in mind we have a 47% working interest and about an eighth royalty. But we would expect that in 2007 that we could be in the range of 300 to 400 million a day gross. So that kind of gives you the profile as you go from 2004, ‘05 up through ‘07.

Brian Singer: That’s helpful. Switching to Patina, I don’t know whether it’s too early to comment on the potential capex that you might spend there in the, assuming the transaction closes at the end of the first quarter.

Chuck Davidson: Well yes. I wouldn’t want to comment any beyond, Brian, what we gave in the original announcement of the transaction. We did give some pro forma guidance for the combined two companies. And their piece of it was around $260 million. But again, I’d refer you to the S-4 and all the original documents on that.

Brian Singer: Thanks, Chuck.

Operator: Thank you. The next question comes in from Ryan Zorn. Please go ahead.

Ryan Zorn: Good morning.

Chuck Davidson: Good morning.

Ryan Zorn: A little more background on Cadillac if I could get it, with several parties in there. Is that legacy and Chevron acreage, or is that something that they’ve developed recently?

Chuck Davidson: That is, that actually dates back to the legacy Noble Energy/Chevron acreage position. So we’re the two primary parties in it. And the way that was originally set up was that Chevron and Noble were 60/40 in the shallow horizons, and we had 20% in the deep and they had 80%. The history of this goes back to 1997 when Chevron and Noble attempted a test of the Cotton Valley. We just got into the upper Cotton Valley and mechanically had problems with a well. But saw enough encouragement that that basically set up the prospect, which again is a very large prospect. It probably, now I guess it covers oh, eight to ten blocks, of which the acreage is held and again most of it because of the shallower James Lime production that’s been in the area.

     And then since then we have held our original 20% working interest and Chevron-Texaco has promoted in a number of parties and as a result, as I mentioned, we’ve got six companies in on this test right now. It’s currently drilling at about 17,000 feet.

Ryan Zorn: Okay, so you’re still heads up on your, on your 20%?

Chuck Davidson: Yes, yes. We’re basically ground floor.

Ryan Zorn: Okay. And then the other four parties are, do they have rights to participate in the remaining block should this be successful?

Chuck Davidson: That, they made their deal with Chevron-Texaco. So I can’t really comment on that. I know we retained all our interest in all the blocks.

Ryan Zorn: Okay. Should this be successful is this something that sees follow-up in the second half of the year?

Chuck Davidson: There will be some follow-up but this is going to be a drill and test. And it’s a fairly significant well with the completion costs substantial as well. So, and again it’s going to 25,000 feet. So I would expect that 2005 will be primarily evaluation. But again, it’s a very significant prospect for the traditional Gulf of Mexico shelf and a very unique horizon.

Ryan Zorn: What brought this back to the table? Is it advancements and completion practices, or prices, or a little of both?

Chuck Davidson: Well I think that from our perspective and I’d have to go back that I first saw this prospect probably within 30 days of walking in the door here several years ago, but the regional work was not done at that time. And what we really needed was, we knew that the Cotton Valley was there, but what we really needed was more regional work to tell us for instance how we best thought that that position occurred, whether we really believed that porosity, permeability were going to be preserved in this deeper section. And I think both companies have done a lot of technical work. And as you mentioned, certainly more confidence in the ability to drill and complete the well. But it’s really the geologic technical work that I think brought this prospect forward again.

Ryan Zorn: Okay, thank you. Can you go into specific details on your bookings at Swordfish and Ticonderoga at your end?

Chuck Davidson: I don’t have the details on those on the top of my head. I mean...

Ryan Zorn: Do you think you’re fairly fully booked on Swordfish and maybe just a percentage of what you think you have booked at Ticonderoga?

Chuck Davidson: Well I think on both of them there’s, just to keep in mind we could only book to basically, you know, the proved lowest known, there may be some performance additions on both of those that are possible so that, you know, when we give our resource estimates for those prospects those are the full resources. And our proved resources would be less than those resources. But that usually comes through production after a year or so.

Ryan Zorn: Yes, okay. I’ll follow up with Greg on that. Last thing, your, the insurance accruals, could you walk me through the mechanics of that? And I guess, when you add that back to get you a clean number is that because you just you hadn’t got it to that, your LOE number? I mean, I guess what I’m asking is, is that something that stays with you at some level or is that purely a fourth quarter item?

Chuck Davidson: That was a, and I may ask Chris to add some more on that, but that was a fairly unique item that hit the industry this year and it has to do with our participation in OIL, Oil Insurance Limited, a large insurance consortium. And it was believed, as the accountants look at prior pronouncements, that there could be a unique situation where you’ve got a liability that, and it had not been recorded. As far as I know I don’t know of anybody who had recorded this on their books before. We decided to go ahead and record it. Going forward there would primarily just be an adjustment to whatever that number is. So, going forward, we would, you know, probably see it as much smaller.

Chris Tong: Yes, there may be an impact going forward, but as Chuck said, it would be much smaller. And the way this works is sort of a historical running total number. So to the extent that our premiums in the future actually reduce that accrual, so to speak, then you can see some positive adjustments or lower interest expense going forward. But the, our belief is that the material impact of that recognition is now. There will be other impacts but they will be minor.

Ryan Zorn: Okay, all right. Thank you, appreciate your time.

Chuck Davidson: Yes, thank you, Ryan.

Operator: Thank you. The next question comes in from Irene Haas, please go ahead.

Irene Haas: Hello guys. Any thoughts on the power plant in Ecuador? Are you guys happy with it? Are there any, you know, thoughts of monetizing or maybe bringing a partner at this point?

Chuck Davidson: Well, we’ve always talked in the past about the potential of, you know, perhaps having a partner there. And I would say that we keep the door open on that. But we’re very pleased with the performance of the plant. Obviously, the financial performance this past year has been very good. We’ve seen strong power prices. Also I think what’s been a positive, and it’s sort of if you look closely at the financials you can see it, but we’ve got very, very good results from our drilling this year. We added some reserves, we converted some reserves to proved developed and, as a result, you’ll see the depletion or depreciation rates for Ecuador went down nicely, so it increased our profit margin there.

     So yes, we’re pleased with the results there. The power markets in Ecuador continue to have their seasonal changes, but it’s fairly predictable there. We are, of course, seeing very strong prices right now for power in Ecuador. And of course that’s driven by their demand for power as well as the higher cost alternatives, primarily driven by high bunker and distillate prices that are used to fuel some of the other thermal generators.

Irene Haas: Thank you.

Chuck Davidson: Thanks Irene.

Operator: Thank you. Your next question comes in from David Khani. Please go ahead.

David Khani: Yes, hi guys. Can you hear me?

Chuck Davidson: Yes, I sure can.

David Khani: Okay, great. Could you walk through a little bit more of what you think you’re going to do in Equatorial Guinea? You talked about two wells, sort of maybe target sizes and have you brought in partners for that or are you going to drill it 100%?

Chuck Davidson: Oh, on Block “O”, Dave, we have, the partnership is all set up and we have a 40% working interest in Block “O”. The government has an interest in there. We have another partner there as well. So that sets the interest in Block “O”. We’ve had a mix of prospects of both, really, of a variety of different prospects. But the ones that are probably most attractive are some large channel features. And they are in the size range of 50 to 150 million barrels equivalent. And, almost certainly, one if not both of these initial wells will be targeting those types of prospects. But in the past we’ve just kind of shown some maps, and we’ve got again a number of other opportunities there in Block “O”, but the, but those are the large features that we’d be initially targeting.

David Khani: And does it set up additional prospects?

Chuck Davidson: Oh absolutely. Yes, this, these, there’s I’d say that we’d see a number of prospects that are independent. But there are others that are clearly follow-on opportunities, depending on what we see there. I’d also comment, you know, we also have another block that we secured in Equatorial Guinea, Block “I”. And it’s possible that we may have, it may be possible that one of the wells will go into Block “I” this year, but that’s yet to be determined.

David Khani: That was supposed to be in ‘06 though if I remember correctly, right?

Chuck Davidson: Yes, that was our original thinking is Block “I” would be in ‘06. But again, depending on what we test and the dependence between those is, that it might push it up into ‘05.

David Khani: Slam Deep, could you give us, refresh memory on the size and who are the operator and the working interest?

Chuck Davidson: Slam Deep, we’re the operator. It’s a deeper test, we had had a shallower prospect there a couple of years ago that didn’t work out, but there’s always been a deeper prospect. And again, we’re the operator at 34% interest. It’s in the Mars basin. And roughly it’s about a 50 million barrel prospect, the P50 is a little less than that and the P mean is a little above it. So I just think of it in terms of a 50 million barrel prospect.

     We would be, again we’re in about 3,600 feet of water and the well will go to about 24,000 feet. I think it’s a prospect, the partnership is already lined up on it. But we still have to go through getting all the partnership approvals. But again, we think it’s most likely to drill following our Lorien work that we’ve got going.

David Khani: Is there any tie back potential?

Chuck Davidson: Yes, it would. It’s probably the best case would be a couple of well tie back. And there’s, in this basin there’s a lot of infrastructure, so there’s several possibilities. But there’s one in particular we’re looking at, but we’ll just have to wait and see the results of the well before we go forward. It is the type of prospect that, depending on its ultimate size, it could drive a stand-alone development. That’s kind of the good news and bad news. The good news is it’s much larger, the bad news is it would probably take longer to develop. But it is of that category that if we saw, for instance, some of the upside on it, it could push us to stand-alone.

David Khani: Could you, and then last moving over on some more exploitation, Niobrara, the 200 wells I think that you’re drilling, could you give us again, refresh us on the size. Are those kind of like the .1, .2 million cubic feet a day kind of wells?

Chuck Davidson: Yes, yes. They’re, you know, we, I, kind of keep in mind they’re 100, 150 Mcf a day. You know 300 Bcf type reserves per well. Very low drilling costs, $140-$150,000. These are 3,500-foot wells. So, obviously it’s a lot of wells. And so when you look at it, it does add up when we have 200 plus wells there this year.

David Khani: How much running room do you have?

Chuck Davidson: That, the approved spacing I think would, we would be just about drilling up all the increased spacing. There might be a little bit of leftover into 2006, but this would get most of it Dave.

David Khani: Okay. Is there any more acreage, or I guess you really probably won’t talk about that, but is there potential to build this?

Chuck Davidson: Well there’s always people buying and selling up there. But it’s, the Niobrara has been developed and this is an in-fill program. So it’s not like you’re doing a lot of expansion onto new acreage. It’s basically further developing your existing acreage.

David Khani: Just continued down-spacing, down-spacing...?

Chuck Davidson: Yes, just continuing to drill down.

David Khani: And then last, Iron Horse, two to three wells. Does that mean positive things are coming?

Chuck Davidson: Well we’re, you know we were, we mentioned before we were encouraged about the shallower potential that we saw. I think there’s still on the exploration mind some thoughts about the deeper, but what we’re really thinking of is the shallower section. We’ve since drilled another well. We’re just in the process of completing

it. And so I think that we’re still thinking that this has got potential, and but we’re kind of seeing what the long-term performance is as well. So we’ve got, as I mentioned, we’ve got a couple on the schedule either as drills or we’ve got some other wells in the area that we may recomplete up into this section as well.

David Khan: All the two to three will be shallower I guess?

Chuck Davidson: That’s the thinking right now.

David Khan: Okay, great. Thanks, good quarter and I’ll let somebody else ask questions.

Chuck Davidson: Okay, thanks Dave.

Operator: Thank you. The next question comes in from Kenneth Beer. Please go ahead.

Kenneth Beer: Good morning guys.

Chuck Davidson: Good morning.

Chris Tong: Good morning.

Kenneth Beer: Just looking to address the, you all have a lot of activity going on in ‘05 both offshore and onshore. Just in terms of service availability Chuck, or cost, is that beginning to be a problem? I mean, you highlighted the Niobrara play as one that you’ve got a lot of running room, but if that 140 or 150 goes up, though, to 175 to 200, does that screw up your economics? If you could just give us some sense as to how you’re going to handle costs given the type of jump in activity you might experience in ‘05?

Chuck Davidson: Well you know, part of it was that when we saw what we’re putting together we did a lot of work, and we also made some commitments in 2004 to get us in position. So the reason we’ve got three rigs running in the Niobrara is we made that commitment in ‘04. And the reason we’ve got a deepwater well drilling right now at Lorien is because we made the rig commitment and then we since added to the time commitment on that so that it can accommodate the follow up exploration drilling at say Slam Deep, as well as some of the completion work that we’ve got to do.

     So a lot of planning went into this programming. This is of, I mean we look at a domestic, we now have the drilling schedule completely filled out to the end of the year with every well scheduled on it. And so we’ve secured, I think in terms of the service, services, we’ve secured the services. Yes, there have been some cost increases. Some of that has been mitigated by getting some of these contracts early. But that has all been really taken into account as we’ve looked at the economics and the justification for the projects.

Kenneth Beer: So you don’t really, you all had, when you say you’ve scheduled out, you not only know what the timing is, but you literally have the, ultimately, the rigs and crews set up for that. So it’s not a question of finding new crews or finding new rigs, you’ve got them identified.

Chuck Davidson: We are, our estimate is we’ve got about 80% identified and tagged right now Ken. And then the remaining is some of those odds and ends. Wells that you always are fitting into the schedule as we see it, or at the very tail end of the year, some fill-in things. But I think for these big programs, we’ve got, for instance we went out and secured the rig to do the Viosca Knoll James Lime. And so it’s been, it actually started doing some work for us in 2004, it was another example of where we tied up the rig and now it’s continuing on and will continue to go into the James Lime exploration program. So we did some things to get a little ahead of the curve and did a lot of planning.

Kenneth Beer: Great. One last question. Just going back to Equatorial Guinea, you’re well into Phase 2B. When that’s over, if I remember correctly, you’re pretty much done, or at least the understanding is you’re done. Any other, do either you or Marathon have any other plans that might be a 2C out there that we just hadn’t heard from you on?

Chuck Davidson: Well, there’s a couple of things I would mention. One is that we’re, we’ve been doing some interesting drilling lately that is in an oil rim of the field that was non-existent, did not, really was not known to exist before. And I think we’re on a second well there. And that has some potential to enhance the production above the levels that we’ve talked about before. Again, we’ll have to see the size and the extent of that. But that has some potential.

     Also, if you jump a little further ahead and you go all the way to the end of 2007, probably 2008, you’ve got the phase 3. Which is, as you know, we noted on our reserve press release that that LNG project was sanctioned this past year. And so in 2008 we’ll begin sale of a substantial amount of gas, perhaps about 130 million net our share will go into that LNG train there.

Kenneth Beer: Right.

Chuck Davidson: So it’s a pretty solid path all the way through 2008.

Kenneth Beer: All right, I’ll stop there, but thanks, appreciate it.

Chuck Davidson: Thanks Ken.

Operator: Thank you. The next question comes in from Michael Somogyi; please go ahead.

Michael Somogyi: Yes, good morning. Could you guys spend more time walking through your balance sheet? You have a consolidated balance sheet on schedule 2, could you do a better job breaking out your total debt between short term and long term, and what your target measures are, if any, regarding your leverage ratios and how you communicate that to the rating agencies? Thank you.

Chris Tong: Well on the, sure, on the debt side, we don’t really have any current maturities. We have two bank credit facilities right now that are $400 million facilities. I think they expire in ‘07 and ‘09, ‘06 and ‘09, sorry. And we have some longer-term bonds out there. So we don’t really have any current maturities to speak of. We, and I’m sorry, the other part?

Chuck Davidson: Long term leverage. I think in terms of long term, we had looked at debt-to-equity, at one time we looked at debt/equity and the targeting in the low ‘40s, but obviously with the strong commodity price environment that’s dropped down into, and with our strong earnings we’ve had we’ve dropped down into the 30’s.

Chris Tong: Then you have a substantial amount of cash on the books. We are looking at ways to try to move some of those funds as a result of the tax act to see if we can get some funds back in and pay down some debt with that. We have $150 million equivalent in cash. Not all of which we’d move over because we need to leave some. But probably at least $100 to $125 million potentially that we could move over. But that is something we’re looking at and trying to figure out a good plan for that.

Michael Somogyi: Now what was the total cash balance at year-end? It’s not the 150, that’s the amount that you guys will look to bring back obviously to pay down debt. But what’s the total cash balance?

Chris Tong: About $179 million.

Michael Smokey: About $179 million, okay. What about your dialogue with the rating agencies? You have a negative outlook, you’re still on review at S&P for potential downgrade. Are you guys targeting you know (Inaudible) ratings? Are you, how many...

Chuck Davidson: We’ve been investment grade for quite some time. And we believe that that’s very helpful to us as we carry out our international business. And we certainly would intend to remain investment grade. The rating agencies review of us, really, I would have to call your attention to the all the announcements on our announced

merger with Patina and the S-4 proxy and the pro formas that are included in that. They have, of course, not been judged final yet. But all of that really relates to that transaction.

Michael Somogyi: Okay, thanks very much.

Operator: Thank you. Your next question comes in from John Herrlin; please go ahead.

John Herrlin: Yes, good morning.

Chuck Davidson: Good morning.

Chris Tong: Good morning, John.

John Herrlin: On one of your prior releases you addressed your capex for 2004. I was wondering if you could break down the $274 million you spent abroad geographically?

Chuck Davidson: In terms of the 2004 capital spending?

John Herrlin: Yes, exactly.

Chuck Davidson: On the, it was, of our categories of, obviously EG was the greatest. And I’m struggling here to pull up the exact numbers. I’m going to give you a bad number if I do it offhand.

John Herrlin: If you’d like to just get back to me that’s fine.

Chuck Davidson: Yes. I would just say that you know for everybody’s benefit the huge amount, the largest amount was in Equatorial Guinea obviously. We spent very little in Israel and we spent some in Ecuador with the development program. But we’ll get you the exact numbers John.

John Herrlin: Yes thanks, that’s it for me.

Chuck Davidson: Thank you.

Operator: Thank you. Once again, if there are any questions please press *1 on your touch-tone phone. Thank you, there are no further questions at this time.

Greg Panagos: Okay, thank you all very much for listening.

Operator: Thank you very much. This does conclude today’s conference call. Please disconnect your lines and have a wonderful day.

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