Exhibit 99.1

Western Gas Resources Fourth Quarter and 2005 Earnings Conference Call

February 23, 2006

Operator

Good day, everyone. Welcome to the Western Gas Resources fourth quarter 2005 earnings conference call. Today’s conference is being recorded. At this time for opening remarks and introductions, I would like the turn the call over to the Director of Investor Relations, Mr. Ron Wirth. Please go ahead, sir.

Ron Wirth - Western Gas Resources – Director of IR

Thank you and good morning. Welcome to the teleconference for Western Gas Resources to discuss our fourth quarter and year end 2005 results. I am Ron Wirth, Director of Investor Relations. Peter Dea, President and CEO, Bill Krysiak, CFO and Executive Vice President will discuss our performance today. John Chandler, Chief Operating Officer and Executive Vice President is also available for questions.

Before we begin, please note that statements made in our presentation today, other than historical facts are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. While the Company believes these forward-looking statements are reasonable, they are subject to factors, such as commodity prices, competition, technology, environmental and regulatory factors, and the drilling schedules, capital plans, and success of producers dedicated to our facilities, which could cause results to differ materially.

Bill will begin by reviewing our financial performance, and Peter will then discuss our operational performance. Following him, there will be a question and answer session, followed by some final comments from Peter.

With that, I’ll turn it over to Bill for his comments.

Bill Krysiak - Western Gas Resources - CFO, EVP

Thank you, Ron. Good morning, everyone. Western had a record year in 2005. This was fueled by several factors. First of all, we benefited from strong product prices as natural gas prices increased 33%, and NGL prices increased 28% compared to 2004. Secondly and very importantly, we had strong production growth in our upstream operations of 14%, and solid throughput growth of about 5% in our mid-stream operations.

Overall in 2005, we earned net income of $203.8 million, or $2.67 per fully diluted common share, compared to income in 2004 of $127.8 million, or $1.73 per common share. Year-over-year this represents a 60% increase in net income. Cash flow from operations in 2005 increased by 50% compared to 2004, to $417.2 million, adjusted EBITDA increased 45% to $468.9 million, and revenues totaled $4 billion.

In the fourth quarter of 2005, we earned a record net income of $135.7 million, or $1.76 per fully diluted common share, compared to net income in the fourth quarter of 2004 of $60.2 million, or $0.80 per common share. Overall quarter-to-quarter this represents an increase in net income of 125%. Cash flow from operations in the fourth quarter of 2005 increased by 60%, compared to the 2004 quarter to $150.4 million. Adjusted EBITDA increased 104% to $257.1 million, and revenues totaled $1.3 billion.

The financial results as discussed reflect the restatement of our financial statement as of December 2005. This restatement corrected our non-cash mark to market accounting for storage and transportation contracts that were previously treated at derivatives, and did not affect cash flow from operations. While our storage positions are still economically hedged, we are subject to non-cash earnings volatility, resulting from changes in the future price of natural gas.

While this market volatility has historically been less significant to net income over a full year period, it has impacted results in the individual quarter substantially. In the third quarter 2005 our results were negatively impacted by the change in accounting, in the accounting for this mark to market valuation. Primarily due to a drop in the future price of natural gas as valued on September 30, 2005 compared to December 31, 2005 net income in the fourth quarter reflects a $55.6 million benefit, from the non-cash mark to market of economic hedges of future sales of gas. Again, this change in the valuation does not affect cash flows.

Overall our balance sheet at December 31 2005 continues to be very strong, with total debt outstanding of $430 million, and a debt to cap ratio of 31%.

With that I will turn it over to Peter.

Peter Dea - Western Gas Resources - President, CEO

Thank you, Bill. Good morning, everyone. 2005 was an excellent year for Western Gas Resources and our shareholders, both financially and operationally. As Bill said, we delivered a 62% return to our shareholders, and we further positioned ourselves for future growth in the years ahead.

I want to take this time to especially thank all of our employees for their tireless efforts, and our customers and shareholders for their support. We benefited from a strong commodity price environment, year-over-year volume growth in both upstream and mid-stream, and another solid performance from our marketing department, a pretty good combination of events. Overall 2005 was a record year in many regards.

I will now provide a brief summary followed by project specifics. We experienced solid production and reserve growth for the ninth straight year in 2005. Our overall net production in 2005 increased 14% to 63 BCFE from 2004, during a time when overall industry production declined once again. Proven reserves increased 13% to 921 BCFE, as we added 173 BCFE of reserves, net of 2005 production and sales. In 2005, we replaced 275% of production.

Operating profit from production increased 62% compared to 2004, due primarily to strong natural gas prices and production growth. We expect double digit production growth again this year, and have revised upward our production growth expectations to 17 to 22% for 2006. Our gathering and processing volumes increased 5% in 2005 to 1.4 BCF a day. Segment operating profit increased 41% compared to 2004, due largely to higher commodity prices, increased gathering volumes, and greater NGL recoveries.

Our net operating margin increased over 28% to $0.46 on a per MCF basis. Gathering volumes increased in the Green River and Anadarko Basins, and were stable at a very profitable level in west Texas. We estimate gathering and processing volumes will average 1.6 BCF a day in 2006, representing an increase of 12%. Our marketing department turned in a strong performance once again in 2005, as operating profit totaled $25.3 million. Sales margins for gas were $0.044 per MCF. NGL sales margins were $0.009 per gallon. The Transportation segment added an additional $12.2 million of operating income.

On the financial side, we continued to further strengthen our balance sheet in 2005. We reduced our debt to capitalization ratio to 31%, the lowest level in many years. Additionally in the fourth quarter, we increased our quarterly dividend by 50% to $0.075 per share.

In 2005, we also continued our commitment to the environment. For the third consecutive year the Environmental Protection Agency recognized Western for its commitment and contributions to environmental stewardship. We received the Natural Gas Star Continuing Excellence Award. Over the past two years, we received the Natural Gas Star Implementation Manager of the Year Award, and the Processing Partner of the Year Award. Through this program the EPA works with industry companies to identify and promote the implementation of cost effective technologies, and practices to reduce emissions.

Starting in early 2005, Western formalized a program that represents a company-wide effort, to further reduce our own consumption of energy in greenhouse gas emissions. Through our energy and emissions savings program, we have implemented many energy efficiency ideas from our employees, through conservation, improved technology, and renewable sources, such as solar pumps and solar meters. Our industry including Western continues to show that we can help meet the energy needs of America in an environmentally sound manner.

Now let’s turn to our primary business of producing and processing clean burning natural gas. We’ll begin with the Powder River Basin coal bed methane development. During 2005, we drilled 882 CBM wells, a 17% increase from the 732 wells drilled in 2004. Of that total, 720 were drilled in the Big George and related coals. Overall CBM net production increased slightly to 42 BCF. Approximately 40% of our net production was from the Big George fairway.

We plan to drill approximately 900 coal bed methane wells in 2006, including 800 in the Big George fairway, and 100 in the Wyodak fairway. CBM production is expected to increase 11 to 14% in 2006. Production from the more prolific Big George fairway now surpassed production from the Wyodak fairway.

Proved reserves for the Powder River CBM were 339 BCF at year end 2005, and probable possible reserves were 2 trillion cubic feet of gas, according to our independent reserve report, conducted by Netherland, Sewell & Associates. Proved reserves included 266 BCF from the Big George and related coals, a 49% increase from a year ago. 78% of our proved reserves at year end 2005 are from the Big George and related coals.

Net production from the Big George fairway nearly doubled from December 2004 to December 2005. As of year end 2005, Western and its partner have drilled over 2350 wells in this coal. Of that total, approximately 1,050 are selling gas, 500 are dewatering, and 800 wells are drilling and awaiting hook-up. Significant drilling activity is under way in five pilots in the thickest part of the Big George, and new pilot drilling is occurring in approximately seven additional areas.

An additional 2 to 4 pilot areas are expected to begin producing commercial gas in 2006. The recently announced acquisition of 40,000 gross and net acres and 110 drilled wells in the Big George fairway reflects our growing confidence in the future potential of this prolific area. The permitting process remains on-track. We currently have 94% of our drilling permits and 67% of our water discharge permits for 2006, and in-hand or submitted to the different agencies.

As is evident throughout the industry, LOE costs are increasing. In 2005 we held lease operating expense costs to $0.91 per MCF from a budgeted $1.11. However, we are expecting about a $0.40 increase in LOE for CBM operations in 2006. Water handling is the biggest impact on the CBM operations, and accounts for about $0.17 of the total. Keep in mind that many wells are dewatering, but not yet producing gas. So that does inflate the per unit costs from full cycle expectations.

For instance, our average well cost per month, is only expected to go up 9% from about $1100 to $1200 per month, basically in-line with overall industry escalations. Now, in the midstream side, CBM gathering volumes, which include equity, partner, and third-party gas, were nearly 400 million a day in 2005. Approximately 101 million a day of the total volumes gathered were also transported in our wholly-owned MIGC pipeline, to a major interstate pipeline connection.

In total, our 13% owned and operated Fort Union gathering system handled 418 million a day of CBM volumes, including third-party gas. A 90 million a day gathering line we built in mid 2005 for new Big George production is almost full. We’re looking to add compression to nearly double capacity on that line. We’ve also nearly completed another new gathering line of similar size to other new Big George pilot areas, to bring this gas to market.

The Powder River Basin CBM development continues to be a company-building play for Western. Based on current economics, we have an inventory of 7,000 base wells, and 14,000 recompletions due to the multiple coal seam nature of the play. We continue to expect significant production growth from the prolific Big George fairway, as more pilots dewater and begin to produce gas.

Let’s now move down to Southwest Wyoming. Net reserves in the greater Green River Basin increased 16% at year end 2005 to 554 BCFE including 519 BCFE in the Pinedale Anticline in Jonah Field. Net reserves added before production were 94 BCFE including 14 BCFE from the first partial booking of potential 10-acre locations on the Pinedale Anticline. In addition, probable and possible reserves in the greater Green River Basin increased 153%, to 905 BCFE.

These probable and possible reserves include some of the additional potential 10-acre locations on the Pinedale Anticline, and 5-acre locations in the Jonah Field. In total, we estimate approximately 2,650 undrilled locations in the Pinedale Anticline, and another 125 locations in the Jonah Field, all based on 10-acre density. Now dominated by the Pinedale Anticline, total net production in the greater Green River Basin increased 32% in 2005, and averaged 46 million cubic feet of gas equivalent per day.

We are projecting production growth in the Green River Basin of approximately 26 to 33% in 2006. We participated in 109 wells in the Pinedale Anticline and Jonah Field in 2005. Drilling is expected to accelerate in 2006. We have budgeted 122 wells in the Pinedale Anticline, and another 10 wells in the Jonah Field.

However, this could grow even further based on recent indications from our partners. Several catalysts are driving future productions on the Pinedale Anticline. These include increased winter drilling, an increase in estimated gas in place to 44 trillion cubic feet for the Anticline, and increased density to 10 acres. Additionally, we participated in Questar’s 19,500 foot Rock Springs test, which will resume testing this summer. We also plan to participate in Ultra’s deep test, which will begin this spring or early summer.

On the midstream side, we continue to expand gathering processing operations in the area, to take advantage of volume growth from the Pinedale Anticline, Wamsutter and other areas. In 2005 our Granger system south of Pinedale, gathered 319 million cubic feet a day of gas, a 25% increase from 2004. About 75 miles to the east in the Wamsutter area, we integrated our acquisition of 150 million a day Patrick Draw processing plant, and related gathering into our other systems. We now have 192 million a day of total processing capacity.

In December 2005, we gathered approximately 116 million a day in the three adjacent sub-basins, which are the Red Desert, Washakie and Sand Wash Basins. Our newly-combined gathering and processing systems position us for future growth in this emerging new core area for the Company in the eastern Green River Basin.

I will now move to northern New Mexico. We drilled 42 gross wells, or 39 net, in the San Juan Basin during 2005. Year end proved reserves are 28 BCFE. Probable reserves are 22 BCFE, and the total production was 4 BCFE. In 2006, we plan to drill 13 wells, and do 60 recompletions, to perforate additional coals not developed in the past. We are also looking at other drilling opportunities in the San Juan Basin to expand this fully integrated area.

Now on the exploration and acquisition front, our team continues to actively work in a number of new grassroots and other opportunities in the U.S. Rocky Mountains, Canada, and select other

regions of the U.S. In the eastern Green River Basin near the Wamsutter area, we now have approximately 41,000 net acres, and we participated in two gross wells in 2005.

One well IP’d at 2 million a day where Western has a 50% working interest. The other went to sale just this week at 2.8 million a day. We have a 33% working interest in that well. In 2006, we plan to offset both wells and participate in a total of six gross wells in this over-pressured tight gas sand fairway.

Now, the news that all of you have been patiently waiting for is the following, our stealth project has a name and a location. We call it the Northern Plains Biogenic gas project. Our 550,000 gross and net acres is located in central Montana.

Our objective is biogenic gas from a package of rock that includes shale, siltstone and the tight sandstones in the upper Cretaceous age, Eagle, Niobrara, Bowdoin, and Phillips formations. Drilling depths average about 2,000 feet and an estimated D&C cost of $275,000. We drilled three wells in late 2005. Each had gas shows as expressed in the mud log. Actual testing will be done in the next couple of months.

Based on these initial results, and the need to test a large leasehold, we plan to drill seven additional wells in 2006. This play is still in the exploration phase, and will require additional testing throughout the year. The way we look although it is, if it proves successful, it could be another company building fairway-type resource play. If it does not pan out, we will leverage our knowledge into other fairway scale prospects.

In Canada, our new exploration and operations team is meeting with early success in acquiring acreage, forming partnerships, and drilling unconventional gas reservoirs. We drilled 21 gross wells in 2005 in two areas in southern Saskatchewan, and northeastern British Columbia, and we’re in the process of testing or completing a number of wells. Based on early results, we plan to drill 60 wells in 2006. Here we are targeting the Milk River to Belly River tight gas sands, at depths typically less than 2,000 feet.

Now I will move to our pure midstream assets. Our Midkiff-Benedum complex in west Texas is running very well and gathering volumes remain steady, averaging 141 million a day for 2005. Net operating margins from these assets are exceptional. Averaging $1.28 per MCF in 2005. That’s a net number. Drilling activity in well connections are expected to increase to over 300 wells in 2006, as the Sprayberry infield program continues.

In Oklahoma, we connected a record 250 wells, and are well on our way to completing a new 200 million a day processing facility. Activity remains very strong, and we anticipate hooking up another 250 wells in 2006. Gathering volumes increased 12% to 205 million a day in 2005, and is expected to increase further in 2006, once our new facility is complete in the second quarter.

In summary, 2005 was another record year for Western Gas Resources. Share value appreciation of 62% was complemented by double digit returns on capital employed and equity. As we drilled into our vast resource potential, in two concentrated projects, we continue to grow production and reserves for the ninth straight year. True to our strategy, we balance growth with returns. We continue to expand our gathering and processing volumes through our high quality midstream facilities.

Our cost structure is increasing, yet remains amongst the lowest in industry in all of our fully-integrated operations, both upstream and midstream, despite the industry trends and upward cost pressure. Our solid balance sheet got even healthier in 2005, closing out the year with a 31% debt to capitalization ratio, net of cash.

Looking ahead, we are fortunate to have a significant low risk drilling inventory. Our probable and possible reserves of 3 trillion cubic feet of gas equivalent, and exposure to high impact exploratory fairway prospects in the Rockies and western Canada, position us well for future growth.

We would now like to open it up for questions.

Operator

We’ll take our first question from David Tameron of Jefferies & Co.

David Tameron - Jefferies & Co. - Analyst

Good morning. Congratulations on a good quarter.

Bill Krysiak - Western Gas Resources - CFO, EVP

Thank you.

David Tameron - Jefferies & Co. - Analyst

A couple of questions, digging into the production guidance a little bit, was the Powder River Basin the Kennedy acquisition you announced last week, was that included in guidance? For 2006?

Ron Wirth - Western Gas Resources – Director of IR

Well, it is included, David, but it is really not anticipated to have much effect in 2006 if you will, on the production. Because it is not going to really be expected to start-up I don’t think until the third quarter, so I don’t think the effect of that acquisition is really going to impact 2006 in effect.

David Tameron - Jefferies & Co. - Analyst

Okay. And then in the other piece you had, I think you said 16 to 19 million from San Juan and Canada. San Juan about 10 million a day this year or at least that’s where you were at this year. Are we to assume the other additions coming from Canada, the other 6 to 9 million?

Peter Dea - Western Gas Resources - President, CEO

Yes, that’s mostly it, David. It is San Juan is a little bit higher than that, the 11 to 12 million a day range right now. Most of the balance would be from Canada.

Ron Wirth - Western Gas Resources – Director of IR

A little bit in eastern Green River.

David Tameron - Jefferies & Co. - Analyst

Okay. And then looking at the reserve reports, what kind of reserves did you get for some of the Big George locations, was it in-line with the 0.3 or 0.4 you’re talking about, or give us some more clarification on that?

John Chandler - Western Gas Resources - COO, EVP

Yes, David, this is John Chandler. The reserves on the Big George as we have said in the past, vary quite a bit from area to area because of thickness, is obviously different in the different areas, but I would say it was in-line with the numbers that we’ve given you in the past, you know, I think we’ve thrown out ranges, from 200 million up to as much as a billion, depending upon the thickness and the gas content, so it was in-line with expectations.

David Tameron - Jefferies & Co. - Analyst

The performance we’ve seen thus far, now that you’ve had a big chunk online for awhile, how would you rate that versus your expectation?

John Chandler - Western Gas Resources - COO, EVP

I would say those are also in-line with expectations, and we’ve talked about the areas that have been online the longest, and have actually modeled those, including the All Night Creek area, so we have got a lot of history on that area and even the new areas. At this point in time, they are certainly online, in-line with expectations.

David Tameron - Jefferies & Co. - Analyst

Okay. And, Peter, back to you for one question here, getting back to valuation of your stock, sitting today at $43, obviously my NAV says you guys are worth a lot more than that, just based on the midstream and the 25% interest in Ultra, without any of the other assets. Have you guys or are you guys considering, the management team revisiting the whole valuation issue, the split of the midstream? I know you did that I guess we’re coming up nine, ten months ago, but seems to me a little different profile today than what it was back and the discount has widened. Are you taking another look at that?

Peter Dea - Western Gas Resources - President, CEO

Yes, we will, David, now that we soon have today behind us, and all of year end stuff, we’ll start to take a look at that. We’ve already sort of set the stage internally for taking a fresh look at that, but you’re right. Yourself, other analysts and other investors have pointed out that if Ultra is basically 9 billion market cap, and we actually think we’ve got about 22% by the way, but close to 25%, so basically most of their valuation of course, is the Pinedale Anticline, so you can kind of do the math from there, and come to the conclusion that there is a lot of shareholder value yet to be attained with Western on a on par comparison in the Pinedale Anticline, and then giving reasonable values for the midstream and the Powder, and other assets, so we will be taking a fresh look at that.

David Tameron - Jefferies & Co. - Analyst

Okay. Are you going to hire the same advisors? The same type of process you had last summer?

Peter Dea - Western Gas Resources - President, CEO

Yes, it should be we did so much legwork last year on it, so we’re that much farther ahead, and right now it is more a matter of just updating everything. There has been some shifts in the marketplace, too that we’ll be taking a look at. You’ve had other transactions in the midstream to use for comparison purposes as well, and a little bit more history.

David Tameron - Jefferies & Co. - Analyst

Okay. I will let somebody else jump on, and I will circle back. Thanks.

Peter Dea - Western Gas Resources - President, CEO

Thanks, David.

Operator

We’ll hear next from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs - Analyst

Good morning.

Bill Krysiak - Western Gas Resources - CFO, EVP

Good morning.

Brian Singer - Goldman Sachs - Analyst

Question on the Northern plains, how do the characteristics and research resource potential differ from the Niobrara biogenic play you are looking at in the DJ basin? What are the advantages and disadvantages of one versus the other?

Peter Dea - Western Gas Resources - President, CEO

Up there, Brian, in the north we don’t believe it so much of a structural play in the northeast Colorado, it was kind of a regional structure, then in turn broken up by faults, these small normal faults if you will, to then pop up the Niobrara on to little structures. It would cover maybe 80 to 320 acres in size.

You definitely had to be high on the structures. Up here, our model is more of a regional stratographic-type trap model, and it is not too dissimilar from some of the plays that we see north of the border up in Canada. I would say that’s one of the larger differences, plus we’re closer to much larger what we think might be analog fields, again north of the border.

Brian Singer - Goldman Sachs - Analyst

Got it. Have a question on lease operating expense, you highlighted that all the wells that are dewatering contributed to the increased cost per unit. What would you say represents the steady

state LOE if you kind of take that out of the equation, although you will be drilling Big George wells for the next few years, what should we think of as a normalized LOE rate?

Peter Dea - Western Gas Resources - President, CEO

Brian, your question I believe is if you had all of your wells producing gas and contributing to the one side of the equation, what would the actual LOEs, and it would probably be in closer to the $0.80 to $0.90 range. What we’re really seeing is that a large number of wells producing water but no gas, but as long as they’re producing water, you have basically the same lease operating costs, as you do for a gas producing well.

Brian Singer - Goldman Sachs - Analyst

Yes.

Peter Dea - Western Gas Resources - President, CEO

As I mentioned before, that more steady state cost, we estimate would go up about 9%. That’s right in line with this 10 to 15% cost escalation we’re seeing across the board in the industry.

Brian Singer - Goldman Sachs - Analyst

Right. Lastly, follow up on the previous question. Is it just recent transactions that have prompted you to take another look in terms of the midstream separation, or what’s come up in the last six months?

Peter Dea - Western Gas Resources - President, CEO

I think a couple things, Brian. One is we told ourselves and all of you, that we continue to take a fresh look at this every once in a while, and so it’s been about six months since we took a hard look at it. That’s one thing we’ve got greater clarity. We’re closer at least to some of our expansion programs in Oklahoma. That one looks like it will be operational early in the second quarter, and so we’ll have by that time, greater visibility on the contributions of that.

We’ve got a little bit more real life modeled in-house of what the volumes could be, and it is a wide range depending on what level of drilling activity continues, but we think it is going to be pretty robust. Then also frankly, we’ve seen Ultra get a pretty significant valuation increase in the marketplace, which has kind of snuck up on us if you will.

So when you do the simple math you go, wow, our Pinedale could be worth, should be worth north of $2 billion. Then you start looking at as I said before fair market values for the rest, and it is pretty obvious there is some value to unlock. You ask yourself why this is, and why are we not getting full credit for the Pinedale, and don’t know the full answer to that.

Maybe some of you have an answer, but one possibility may be the people get confused with the two different business segments, that Western brings to the table. With that said, we do trade above the pack. We’re trading well above the pack of your typical E&P company by a couple of points, couple multiple points, but good is never good enough. You want to be reaching for the higher valuation companies, and we certainly think we have the portfolio for that.

Brian Singer - Goldman Sachs - Analyst

Very helpful. Thank you.

Peter Dea - Western Gas Resources - President, CEO

Thanks, Brian.

Operator

Thank you. We’ll now hear from Chris Pikul of AG Edwards.

Chris Pikul - A.G. Edwards - Analyst

Peter, I just wanted to say I think you’ve been delivering some great results over the past few quarters, and pretty much accomplished everything you set out to do on the operations side, and you’ve been stealing some of the words from my mouth. The rest is up to investors. If Wall Street can’t seem to add up these two very simple business models, then they’re certainly not as smart as I thought they were. There is a lot of hidden value in your stock.

Before I get too excited about Montana, perhaps can you quickly summarize the different methodologies used in determining the potential reserves on the Big George side of the Basin versus the Wyodak? I know we’ve been through this before. To me, it seems like investors aren’t just willing to pay for any of the upside on your E&P company, and divesting the midstream assets if that suddenly changes their mind, then I definitely don’t understand.

Peter Dea - Western Gas Resources - President, CEO

Thanks, Chris. First of all, I am just one guy on a team of 700 people, plus the Board. It is a team effort here in delivering the results over the last few years. As to the methodologies in the reserves, we’ve had Netherland Sewell for I don’t know how many years, five or six or seven years, ever since we’ve been out there, probably closer to ten, so we’ve had a consistency in terms of the same engineering firm doing it, and what we do is we basically just hand over our data to Netherland Sewell, and their engineers they do all their thing, and by the way, they’re doing engineering studies for most of the other major operators up there, including our partner and some of the other larger operators, and basically just like any other area, they typically rely on the decline curve analysis.

The coal bed plays a little different beast, because you have biogenic, not thermogenic gas. You have gas content, data gas saturation, data and pressure data that they all tie in. We basically give them everything, but I think more than anything they’re relying on those decline curves, and trying to balance that out with some of the other data that they have.

So basically that’s the methodology, and now on the PUDs and the probable and possible, the PUDs they will if you got a producing well, they will give you PUD credit out for a full square mile, so it is beyond just 180-acre spacing units for that full square mile, and then probable is another spacing unit out beyond that, and possible is out beyond that. It is a fairly consistent process, if you will. Does that answer your question on that?

Chris Pikul - A.G. Edwards - Analyst

I suppose. I just remember you still even this year, you took some additional write downs as far as I can tell in the Wyodak, and maybe there is some lingering concern that the 2 TCF is at risk for similar type?

Peter Dea - Western Gas Resources - President, CEO

I have always maintained probable and possible reserves by nature, they come on risk, but obviously anybody is prudent to approach that with some risk factor, as in any play, otherwise it would all be PUDs, basically.

Chris Pikul - A.G. Edwards - Analyst

Sure. They’re all proof for Ultra.

Peter Dea - Western Gas Resources - President, CEO

That’s true. Thanks, Chris.

Chris Pikul - A.G. Edwards - Analyst

Can I follow up real quickly, Peter, on Ultra’s plans like you mentioned to drill 165 wells, would those if indeed they were to achieve that goal, would that indeed be incremental to the production guidance and then number 2, what are the biggest obstacles you see for them maybe not being able to achieve that?

Peter Dea - Western Gas Resources - President, CEO

First of all, whatever wells they drill out, they are most likely we will be participating in. The numbers we released, 122 for the Pinedale and 10 for Jonah, was really based on our budget process that we finished about a month ago, and as you know and we know now, two weeks ago Ultra has expanded their drilling plans for 2006, so as we get greater clarity and confidence in that, we’ll update our budget with additional wells, and as far as the production.

There is probably a pretty good chance that the vast majority of the production associated with those incremental wells, you wouldn’t see until 2007, because once you get up to that November deadline in some areas, we have to wait until the following season to come back and complete those wells unless the BLM gives waivers to go ahead and complete wells during the winter season, where those stipulations are, and those stipulations are not all the way across the Pinedale.

There is quite a bit of Ultra’s acreage that is not subject to those stipulations, so the answer to the production guidance, really depends a lot on when those wells actually, when the incremental wells get drilled so to speak, and where they get drilled on the Pinedale. I would imagine, you know, it could have a nominal increase in guidance for ‘06, but more likely you just kind of get a jump start on 2007 production.

Chris Pikul - A.G. Edwards - Analyst

Thanks again and congratulations to everybody on your team.

Peter Dea - Western Gas Resources - President, CEO

Thank you.

Operator

Thank you. Next we’ll hear from Irene Haas of Sanders Morris Harris.

Irene Haas - Sanders Morris Harris - Analyst

Hi, Peter, I am so glad that finally I can get to know what this true secret project is. Trying to get a little sense on whether the play up there is similar to the ones in Colorado, what not. Are we still looking at roughly 0.4 Bcfe per well, is that the rough dimension we’re looking at?

Peter Dea - Western Gas Resources - President, CEO

The analogs, Irene, are really from southern Canada, and the range that we’re looking at based on kind of P 10, P 50, P 90 type statistical analysis up there, but it is a range. I think what we’re looking for is on the EUR per well of about 0.2 to 0.4 BCF, could be upside to that. That’s probably a comfortable range to fall within. IPs could be in the 150 to 300 MCF a day. F&D costs could range between $0.50 and $1.00, depending on the EUR.

Irene Haas - Sanders Morris Harris - Analyst

How is the infrastructure out there in case this play works out really well, and anybody else out there right now?

Peter Dea - Western Gas Resources - President, CEO

We don’t think there has been anybody else out there chasing our rabbits. People seem to be pursuing some other different types of formations, but obviously we haven’t had a whole lot of competition in the core of our play, but as to the infrastructure, not much.

Some of the test wells that we’ve drilled and will drill next year, will be a little bit closer relatively speaking to pipelines, so that we can get gas to market, but this will be the advantage of having the fully-integrated business segments here, is we kind of embrace those weak infrastructure areas, because we can go out there and put the gathering in, and eventually other people will come in and hopefully we’ll have some third-party profits from that as well.

Irene Haas - Sanders Morris Harris - Analyst

Thank you.

Peter Dea - Western Gas Resources - President, CEO

Thanks, Irene.

Operator

We’ll hear next from Dave Anderson of UBS.

David Anderson - UBS - Analyst

Good morning, Peter. I have a question for you. A little disappointed to hear you’re going to use the same advisors when you’re looking at this midstream possible monetization. I don’t think really valuation of MLPs have really changed that much over the last six months.

I still have them trading around 10.5 times EBITDA, or somewhere around there, and you had mentioned last time you looked at this, that your bankers told you, you would get around 7.5 times EBITDA for an IPO, while over the last six months I have an average of the last four have averaged around 11.7 times. I am a little surprised to hear you’re going to be using the same methodology and the same advisor there, and secondarily could you please put a little timeline on this of when you think you will make a decision? Is this the next three months, six months, this has been something of an open ended question. I think a lot of investors are looking for clarity.

Bill Krysiak - Western Gas Resources - CFO, EVP

Hey, David, this is Bill Krysiak. Relative to the same advisors, and are we going to use those. That’s a Board decision, and we will certainly talk to the Board about all of that. As far as I agree with you. We have seen information, and the last four that you are tracking are much higher, good analog is probably Williams, and they went out at higher than what be previously estimated, a multiple to be out at MLP. That is the type of information that’s changed in the last four months to us, or added clarity to it, that perhaps this is another time to take I look at this, and see where we get to.

Peter Dea - Western Gas Resources - President, CEO

I will add to that we are looking at, trying to hone in on specific comparables for example. Also there has been some transactions, for example, the Sid Richardson sale went at a very high premium, you could call it, or high multiple from that perspective in west Texas, and some other of these MLP’s or midstream companies that we’re going to hone in on, and I think there was some confusion, and we fueled that confusion admittedly with the reference to the 7 times multiple. A multiple is not a multiple. You have to look at these things a little differently. I think the confusion is, or let me clarify it. If you look at a new IPO, then sure, those things can get an 11, 12, even 13 times multiple. Over time what you see is the multiples for those same things, may contract down to a 7, 8, 9 times multiple just depending. And you if begin to look at a broad field of companies, you end up with an average that might be diluted down by entities that are frankly inferior to our assets.

You do end up with an average, so we’re aware of a wide range of multiples depending on what you’re talking about. I think I would give you comfort that we’re going to be looking at a narrower range of closer specific comps to Western’s high quality asset base, and take a look at not only how they’re trading, but also sales transactions.

As to the timing, we’re really just kind of readdressing this right now, because obviously we’ve been pretty busy with our year end 2005 reserves, earnings. We still have the 10-K to get out. We will be focusing on this with a lot of diligence here very shortly, and I would imagine it would be at least a couple months process to go through it all, and can’t predict the outcome yet, but I think more than ever, we certainly see the value of arbitrage there that we should be getting more than we are in the Street, and I think you amongst others have put the nail on the head, and so we’re taking a pretty close look at it.

David Anderson - UBS - Analyst

I agree with you totally on both of your points especially on the quality assets. The last couple we looked at have been, I would call them quite inferior in terms of asset quality compared to

what you have, and a lot of these have been slapped together the last six months, and they put them out to market. I would think that with the organic growth you have there, you would get quite a bit more.

Just one other quick question on Montana, when I see Montana I immediately think permitting issues, and you have had your fair share of permitting issues over the last five years or so. I think most of the permitting issues I am familiar with are on the northern part of the Powder River Basin. Can you talk to me a little bit about any concerns we might have in the Montana area, of what you’re talking about now, and how that looks going forward, please?

Peter Dea - Western Gas Resources - President, CEO

We’ll have permitting to go deal with up there for sure. We do have a combination of federal fee and state land. What we would hope to be able to do, is do a lot of the initial testing maybe the initial confirmation development wells on fee lands and select federal lands, but any time you’ve got any kind of a material position in the Rocky Mountains, you typically have the BLM and that related permitting process to work with.

David Anderson - UBS - Analyst

How many permits do you think you need over the next couple of years? Do you have any idea yet, or is it such an early stage you’re not there yet?

Peter Dea - Western Gas Resources - President, CEO

We have some preliminary pro formas in and we’re up in the tens of wells, with 60 or so. We’re thinking once we get past the testing phase of 2006, then we could get into a 60 well a year program thereafter, subject to getting permits and all of that type of thing. I mean once we have a sense that there’s commercial gas, we would try to get after it quite well. Somewhere in there, we’ll most likely have to do an environmental impact statement, but at least we’re for better or worse, ‘pros’ at that, and we would start that process as early as we possibly could, maybe even in tandem with some of the early confirmation development drilling.

David Anderson - UBS - Analyst

Presumably all your experience of overcoming permitting issues in the Powder River, should help you up in Montana I would think.

Peter Dea - Western Gas Resources - President, CEO

That’s right. We’ve got a lot of our staff here that has had a lot of relationship building with the BLM, and we work together, and it took awhile but I think we got to a pretty good place in the Buffalo field office, after a lot of work with them.

David Anderson - UBS - Analyst

Okay. Thank you very much, Peter.

Peter Dea - Western Gas Resources - President, CEO

Thanks, David.

Operator

Up next we’ll here from Sebastian Iannariello of Smith Barney.

Sebastian Iannariello - Citigroup - Analyst

Good morning. On your Canadian production, I want to clarify, the target you’ve given out for 2006, that includes the additional 60 wells you’re plan to go drill there, is that correct.

Peter Dea - Western Gas Resources - President, CEO

Correct.

Sebastian Iannariello - Citigroup - Analyst

And can you share with us any of the log data, or I guess on a bigger picture what kind of EURs you’re looking for out of those wells, or what you experienced?

Peter Dea - Western Gas Resources - President, CEO

This would be really preliminary, more based on the analogs that we have up in that area, and there are some fields that are within a few tens of miles that we’re playing off of. We could see an EUR range in the 0.2 to 0.3 BCF. The initial rates could be anywhere from 100 to 300 MCF a day. Wide range, but that’s the nature of the beast, when you look at a field that’s got several hundred wells, you just see a pretty wide range. It gets to be a bit of a statistical play, if you’re in one of those gas traps where most of the time you will have gas, and it is just a matter of the permeability and the reservoir quality.

Sebastian Iannariello - Citigroup - Analyst

Okay. Thanks. Going back to the midstream and the MLP issue, can you remind us what the tax basis is, or approximate tax basis is on these assets?

Bill Krysiak - Western Gas Resources - CFO, EVP

Yes, Sebastian. This is Bill again. I think in total, and I haven’t looked to see where it is at the end of 2005. Roughly we had about 500 million of tax basis on our combined assets, so split if you will between the two, 50/50.

Sebastian Iannariello - Citigroup - Analyst

And then the keep whole exposure, that’s roughly 40% of your gross margins, is how you look at it? Is that still correct?

Ron Wirth - Western Gas Resources – Director of IR

Keep whole is much lower than that. About 10%.

Sebastian Iannariello - Citigroup - Analyst

And your POP?

Ron Wirth - Western Gas Resources – Director of IR

About 70%.

Sebastian Iannariello - Citigroup - Analyst

Okay. And then can you give us the breakdown for your Wyodak and big George production for the quarter.

Ron Wirth - Western Gas Resources – Director of IR

I can give you help there, Sebastian. In the quarter I guesstimate about 48% of the production would have been Big George and fairway, and for the year would have been around just under 40%, about 39 and change percent for all of 2005, and as Peter noted earlier, the Big George has now crossed the Wyodak, in terms of daily production.

Sebastian Iannariello - Citigroup - Analyst

Okay. Perfect.

Operator

Thank you. Up next, we’ll hear from Suniel Jagwani of Citadel.

Suniel Jagwani - Citadel - Analyst

Congratulations on a good quarter again. The question I had was about the integration in the midstream assets. What portion of your EBITDA do you think you will be able to separate out from the Company, without impacting your operations, if you can put some ranges around that?

Bill Krysiak - Western Gas Resources - CFO, EVP

I am sorry. I don’t quite understand the question.

Suniel Jagwani - Citadel - Analyst

Just if you look at your midstream segments contribution, what percentage of the EBITDA of that business do you think you can separate, without impacting your upstream operations?

Peter Dea - Western Gas Resources - President, CEO

While Bill is looking into that detail, the preface for that, Suniel, would be what are the pure mid-stream assets, where we don’t have any direct ties to our own exploration and production. The two big cash cows are the West Texas asset base and the western Oklahoma asset base.

The question becomes, that would be the bulk of it. The EBITDA for those two and do we have that broken out, Ron, we could probably get that later.

Ron Wirth - Western Gas Resources – Director of IR

We don’t have that broken out.

Peter Dea - Western Gas Resources - President, CEO

We roll everything into the business segment. We’ve got it internally. We just don’t have it at our finger tips right now to give you an accurate number. If you want to call Ron, he can give you that answer. I would guess that people are going to use this as some sort of model, maybe 50 or 60% of the total would be those types of assets.

Suniel Jagwani - Citadel - Analyst

Thank you.

Operator

Thank you. Now hear from Chitra Sundaram of Cardinal Capital.

Chitra Sundaram - Cardinal Capital Management - Analyst

The first is on the finding and development cost, it went up to $1.26 from $0.78. Maybe the number is wrong. That is primarily because of the dewatering of the wells in the Big George?

Peter Dea - Western Gas Resources - President, CEO

Yes, a combination of things, but that’s part of it. If you look at the raw per well F&D cost in the Big George, we’re still looking around that $0.50 to $0.60 range. The total corporate F&D of course is burdened by as you pointed out wells that we’ve drilled but haven’t booked any reserves on, which would be quite a few in the Powder, the same thing in the Pinedale, and then also thrown into that total number is the exploration, leasing, seismic, drilling of exploration wells, that we also have virtually no reserves booked on, any addition on that, Ron?

Ron Wirth - Western Gas Resources – Director of IR

Also, any wells where you are converting PUDs where you are expending dollars on PUDs to convert to producing wells.

Peter Dea – Western Gas Resources – President, CEO

Good point. We did have a number of…fair number of conversions of PUDs to PDP. So you already had those reserves in the proven category. You spent dollars to drill the PUDs, but you didn’t get another molecule of gas booked necessarily.

Chitra Sundaram - Cardinal Capital Management - Analyst

So the way to think about this is actually predominantly, it is because of the growth in the asset base that you’re investing in? I guess when we started looking at the main, one issue I discussed with you Peter in our conference call is about the dewatering issue in Big George, and kind of when would that sort of, those wells start getting converted into producing wells, which would then add to the reserve and so forth, but you’re saying that issue is kind of going away fairly steadily —

Peter Dea - Western Gas Resources - President, CEO

Well, it is kind of a rolling forward type situation in that wells that we drilled last year for example in 2005, that are dewatering now, and you may not have any reserves booked on them until probably a combination of 2006 and 2007, so those would finally be contributing to reserves, and balancing out the CapEx, but meanwhile in 2006, we’re going to drill 900 fresh new wells that for the next 12 months or so, will be kind of burdening that debt calculation, just because you spent real money, but you don’t have any reserves booked on it yet.

The other item of course is cost escalation by the way, but with that said, all of those other factors go into it. It is probably about four or five factors there that have contributed. When you look at our pure F&D on a one well basis, we’re still in that $0.70 to $0.75 range for the Pinedale, and you can get different numbers depending on how you calculate that too. That’s how we come up, internally. If you look at a pure one well successful case that you booked reserves on, and look back and see what you spent in the Powder River, you’re in the $0.50 to $0.60 per MCF range.

Chitra Sundaram - Cardinal Capital Management - Analyst

Where I am coming from is that original point. which is that my understanding and hope was that as we went, there was sort of a backing up of wells that had taken place through the first half of ‘05, I believe, and I had seen the dewatering in some new exploratory wells going more quickly, and the permitting process catching up with everything else, that I had expected perhaps in ‘06, and maybe that’s why the range has gone up as well operationally I am not sure, but I expected that there would be a greater than average number of wells coming into the reserves, and becoming productive in ‘06 and ‘07, although it is a rolling average to be sure.

Peter Dea - Western Gas Resources - President, CEO

That’s a good point and another part of that you just mentioned is that we also have about 500 wells that have been drilled, but haven’t been hooked up, and they’re not even dewatering yet, and because we had such a flurry of drilling activity at the second half of last year, this just takes time to get those up.

We have a goal to bring that down to about 250 wells here by this year, so we will, maybe that was the bubble of wells that you might have been talking about, and so that will be working its way downward, and we’re pretty focused on that this year as well.

Chitra Sundaram - Cardinal Capital Management - Analyst

Okay. The second thing I just quickly if I might is, when we try to understand return on investment, because this is a fairly capital intensive business for good reasons, the all-in cost I guess, finding, development, and perhaps acquisition is kind of the investment per well is it not on average for the company, and how should we think on the return on that, and what are the thresholds you all have perhaps, and how would you guide us to look at it? Am I making sense?

Peter Dea - Western Gas Resources - President, CEO

Are you talking about the corporate return on capital employed, or the return on specific projects and wells?

Chitra Sundaram - Cardinal Capital Management - Analyst

E&P, yes, without looking at the midstream and all of that, so you are putting money into all of these new wells and obviously new areas you are trying to develop, but at any give pointed in time, 60% maybe of that asset base is generating operating profit.

Should I just be taking the operating profit divided by the total number of producing wells, and so I kind of get an operating profit per well, and then divide that by the F&D? I am trying to understand how you all think of ROIC in the E&P business.

Peter Dea - Western Gas Resources - President, CEO

Well, one way on a per well basis, it is easy to calculate the rate of return on the per well basis, which we’ve gotten typically these days are all well over 30%. Some of them are 50%, and some 100%. It just depends. We’ve got the rate return on a per well basis, now if you look at a total project that would kind of the return would be a little burdened, because as you’re alluding to, you have spent capital, but you don’t have any revenue stream coming in yet, to offset that from a return perspective.

Chitra Sundaram - Cardinal Capital Management - Analyst

Okay.

Peter Dea — Western Gas Resources - President, CEO

That’s the nature of the, our business basically. Depends on where you are. I mean, if you’re in the Gulf of Mexico, you have got a pretty high rate of return pretty high PV, because you’re getting everything back pretty quickly, versus up here in the Rockies, you have got more long lived reserves.

There is an offset in the Gulf of Mexico, you’re on this wicked steep treadmill, because the production is coming off pretty quickly, but your returns and your MPV can look pretty strong, where up here you may sacrifice to some extent, but you have long-lived reserve and in some of these plays up here, like the Pinedale, have the best of both worlds. You have 50 to 100% rate of return and long-lived reserves, and very high rates and very high reserves.

Chitra Sundaram - Cardinal Capital Management - Analyst

The returns that you just talked about, 30 to 100%, is that primarily because of high natural gas prices, that they are as high as they are, and if that is the case, then what is it on a normalized basis, if you consider the production I guess which is fairly long — ?

Peter Dea - Western Gas Resources - President, CEO

Those ranges that I just threw out are probably in the $6 type NYMEX-type gas price, and obviously we put together and it is all price dependent of course. I try not to get carried away with 7, 8, $9 gas. Once again, most of our projects were put together at a $3 gas price.

Chitra Sundaram - Cardinal Capital Management - Analyst

The 30 to 100% range you’re seeing is feasible at say a $6 gas range.

Peter Dea - Western Gas Resources - President, CEO

You really have to look it, on a per-project basis, so I think if you wanted to drill into that more detail, feel free to call Ron, and he can give you details on it.

Chitra Sundaram - Cardinal Capital Management - Analyst

Thank you.

Operator

Thank you. Next we have a follow-up from Chris Pikul of AG Edwards. Mr. Pikul, your line is open. We’ll move on. It appears we have no further questions at this time. I would like the turn the call back over to Mr. Peter Dea for any additional or closing remarks.

Peter Dea - Western Gas Resources - President, CEO

Well, thank you. I wish to thank all of our 700 plus employees for their ongoing hard work, integrity, and their commitment to the Company’s goals, core values, and the environment. They help deliver our shareholders another record year of very favorable returns on their investment. Despite recent record levels of rig activity and capital spending, the industry still struggles to achieve flat, yet alone positive production and supply. However, for the ninth year in a row, Western has bucked that trend by increasing our supply of clean burning gas to America.

Western Gas is favorably positioned to deliver strong returns and growth to our shareholders. We are embarking on several new high potential, high impact projects, focused on unconventional gas resource plays, to complement or 10 to 15 year development drilling inventory in our two low risk, high potential plays.

We thank you for your support and interest in Western Gas. We look forward to seeing you on the conference circuit in the coming months, as we share and update our exciting story with current and prospective shareholders. Thank you very much.

Operator