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Executives

Norman F. Swanton - Chairman, President, and Chief Executive Officer

Timothy A. Larkin - Chief Financial Officer and Executive Vice President

Kenneth A. Gobble - President and Chief Operating Officer of Warren E&P

Analysts

Leo Moriani - RBC Capital Markets

Irene Haas - Canaccord Adams

Duane Grubert - CRT Capital Group LLC

Mark Lear - Sidoti & Co.

Jack N. Aydin - KeyBanc Capital Markets

David Tameron - Wachovia Capital Markets, LLC

Warren Resources, Inc. (WRES) Q2 2008 Earnings Call August 6, 2008 10:00 AM ET

Operator

Welcome to the Warren Resources second quarter 2008 earnings conference call. (Operator Instructions) I would now like to turn the call over to Norman Swanton, Chairman and Chief Executive Officer.

Norman F. Swanton

Thank you for joining us for the Warren Resources second quarter 2008 financial and operating results conference call. I am here with Tim Larkin, our Executive Vice President and CFO. Ken Gobble, our COO and President of our operating subsidiary Warren E&P, Inc., is also joining us from Wyoming to discuss our operating results. Before I turn the microphone over to Tim to cover the financial results and Ken to discuss our operating results, I would like to briefly review some of our second quarter 2008 highlights.

From a production perspective Warren Resources had its 15th consecutive quarter of record production growth since becoming a publicly-traded company in December 2004. During the second quarter of 2008 compared to the second quarter of 2007 oil and gas production increased 43% to a record 2.2 bcfe, oil and gas revenue increased 157% to $34.2 million and net earnings increased 560% to $0.30 per share compared to $0.05 per share for the second quarter of 2007.

While historically high oil and gas prices have amplified second quarter financial results, I believe the gains in operating results in the second quarter of 2008 are the true drivers of future shareholder value. These achievements include: Successfully drilling additional horizontal Tar wells into D1A sand in California; drilling our first productive horizontal well into DU sand in the Tar formation; finishing the drilling and production sellers number one and number two in the central facility in the Wilmington Townlot Unit; successfully drilling our first two horizontal producers in the stratified ranger oil zone in the North Wilmington Unit; and successfully drilling 60 coalbed methane wells that are exceeding our expectations in the Sun Dog Unit in the Atlantic Rim project in Wyoming. Based on the implications of these and other operating results, I believe we are now well on our way to demonstrating the huge untapped potential of our oil reserves in the Wilmington field units in California and the natural gas reserves in the large emerging Atlantic Rim coalbed methane project in Wyoming.

Additionally, despite short term challenges I am confident that we will resolve our environmental issues in California in a timely manner. I believe that our long-term outlook has never been better. We will continue to build the foundation to deliver strong growth in domestic production reserves and profitability for the years ahead in all of our core US drilling areas.

With that overview I will turn the call over to Tim Larkin, our CFO.

Timothy A. Larkin

Before I discuss the company’s second quarter 2008 financial results released earlier today, I would like to remind you that all statements made during our conference call that are not statements of historical fact constitute forward-looking statements and are made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results could vary materially from those contained in the forward-looking statements. Factors that could cause actual results to differ materially from those in the forward-looking statements are described in our Forms 10Q and 10K and other periodic filings with the SEC and our press releases.

As Norman mentioned, the second quarter of 2008 was an excellent quarter for us. Net income for the second quarter was $17.7 million or $0.30 per share which represented a 560% increase over the $2.7 million of earnings in 2007. Total production was 2.2 billion feet equivalent or 23.8 million cubic feet equivalent per day. This represented a 43% increase over 2007. Gas production for our Sun Dog Unit in the Atlantic Rim project increased significantly. As a result overall gas production increased 163% to 657 million cubic feet during the second quarter compared to 250 million cubic feet during 2007. Additionally, oil production from our two fields in California totaled 252,000 barrels, a 19% increase over the 211,000 barrels produced during the second quarter of 2007. We achieved this growth primarily through the drill bit in the WTU in California. The average realized sales prices for the second quarter of 2008 were $112.25 per barrel and $9.05 per mcf compared to 2007 prices of $57.33 per barrel and $4.98 per mcf.

Total revenues for the second quarter increased 148% to $34.5 million compared to 2007. Oil and gas revenues increased 157% to $34.2 million compared to 2007 and increased 46% over the first quarter of 2008. Total expenses increased 50% to $16.7 million during the second quarter of 2008 compared to 2007. DD&A and lease operating expense increased 75% and 26% respectively primarily due to increases in production. Additionally, general and administrative expense increased as we hired more qualified personnel to support our growth in operations. Additionally we recorded an accrual for projected year-end incentive compensation of $750,000 during the quarter. We did not record a similar accrual in the second quarter of 2007.

We achieved these results despite having second quarter WTU production effectively capped due to the produced gas issue discussed in our press release issued earlier this morning. We are continuing to work with the AQMD to permit the necessary equipment to resolve these issues. Our plan is to receive the permits and install the equipment during the fourth quarter of 2008. Currently the WTU is producing approximately 3,200 barrels of oil per day. We estimate that the WTU production will be limited to between 3,200 and 3,400 barrels of oil per day until we are able to install the equipment necessary to handle the increased gas.

For the first six months of 2008 net cash provided by operating activities increased 188% to $30.3 million compared to 2007 cash flow from operations of $10.5 million. During April 2008 our borrowing base increased by $10 million providing total availability of $135 million under our $250 million credit facility. We did not borrow any funds under the credit facility during the second quarter and maintained and outstanding balance of $82 million as of June 30, 2008. We plan on funding our 2008 capital expenditures budget with our senior credit facility, cash flow from operations, and existing cash on hand. We expect another borrowing base increase during October 2008.

We reported third quarter and full year production guidance in our press release. Due to short-term regulatory issues we have slightly lowered our full-year oil production guidance; however, due to better-than-expected results in the Sun Dog Unit in our Atlantic Rim project we have increased our full-year gas production guidance.

Now let me turn the microphone over to Ken who will provide you with a brief operational update.

Kenneth A. Gobble

Warren was again able to make comprehensive major progress in our major fields including the Wilmington Townlot Unit, North Wilmington Unit, and the Atlantic Rim. I would like to highlight some of the operational achievements that were obtained during the quarter.

In the Wilmington Townlot Unit or WTU we drilled a total of five wells; two producers in the Upper Terminal formation and three horizontal producers in the Tar reservoir. Warren also completed six additional wells that have been located under the large neighbor’s drilling rig. For the remainder of the year Warren is anticipating drilling 15 producing wells and four injection wells in the WTU. Included in our drilling schedule are the first horizontal wells targeting the DU sand of the Tar formation and a well to test the potential of the deeper Ford and U237 reservoirs. Two of the four planned injection wells will be developed to provide pressure support to the existing producing wells in the D1A sand in the Tar formation.

The company continues to make progress in resolving two regulatory issues necessary for the continued growth of the WTU. The Zoning Administration hearing was held on May 2 to review the terms and conditions of construction and operation set forth in the Zoning Administrator’s 2006 Zoning Order. This order allows the company to drill up to 540 wells from the WTU central facility. The Zoning Administrator did not question Warren’s right to drill and operate in the WTU but whether any of the regulations or zoning order conditions were being violated. The company enjoyed enormous support at this hearing from community members, employees, contractors and other interest owners in the unit. Warren expects the Zoning Administrator to render a decision on this matter by the end of the third quarter of 2008.

The second issue, the South Coast Air Quality Management District restrictions concerning compliance with air quality standards and permission to install the best available control technology is also progressing. The AQMD is basically in agreement with Warren’s long-term plans to first upgrade our flare to reduce emissions, second reinject our current flare gas back into oil bearing reservoirs, and finally sell gas directly to a third-party user when adequate gas volumes and equipment are available.

The AQMD has asked that Warren prepare an environmental analysis or CEQA that would cover the permit applications that the company has submitted to the agency for approval. A draft of the CEQA document was submitted to the AQMD on June 17. Warren and its environmental consultants have been working diligently with the AQMD to complete the necessary revisions to the CEQA document prior to posting for a 30-day public comment period. After the comment period, the AQMD will answer comments brought forth by the public at which point Warren expects the AQMD to process the company’s permit applications. Warren currently is expecting these permit issues to be resolved in the fourth quarter of 2008.

Additionally, Warren has scheduled a hearing with the AQMD Hearing Board for an Order of Abatement for August 12 and 13. Approval of the proposed Order of Abatement will strengthen the settle agreement under which the company is currently operating the existing gas flare and six micro turbines until the permit applications covering the new equipment are processed by the AQMD.

Current production in the WTU is approximately 3,200 barrels of oil per day. As a result of gas handling restrictions oil production may be restricted to between 3,200 and 3,400 barrels of oil per day in the future until the AQMD permits the new gas handling equipment.

During the second quarter the company began drilling a five-well horizontal project in the North Wilmington Unit for NWU. This project targets proved undeveloped reserves in the Ranger formation. Currently the company has drilled three producers and one injector with the two producers and the injector now on line for testing. The two producers are averaging between 40 and 50 barrels of oil per day. Pressure support from the injector has only recently been established. The company expects oil production from the two producing wells to increase as water injection volumes are increased in the future.

The promising results from the initial wells in this project have led the company to increase the 2008 budget to allow drilling an additional four wells, two producers and two injectors in the second half of 2008. If production results continue to be positive, Warren plans to expand the existing facility infrastructure to handle the forecast production volumes. This work is currently planned for 2009 and is expected to take between six and nine months to complete. Current production from the North Wilmington Unit is approximately 480 barrels of oil per day.

Warren’s 2007 and early 2008 development program which consisted of 60 producing wells in the Sun Dog Unit of the Atlantic Rim project contributed the majority of production growth for the company during the second quarter. The company has 63 wells producing approximately 14.5 million cubic feet of gas per day. Warren and its partners in the project have commenced development after the wildlife stipulations expired in mid-July.

Warren is planning to drill an additional 100 to 130 producing wells in the remainder of 2008 in the Doty Mountain, Sun Dog and Blue Sky areas of the Atlantic Rim project. Approximately half of the planned wells will be drilled in the Sun Dog Unit. Expansion of facility infrastructure including water injection, electrical generation, and gas compression is also now underway in the project area. There is currently one drilling rig presetting surface casing and another drilling rig active in the Sun Dog Unit. The arrival of two additional drilling rigs is expected in the next few weeks. Rig count in the Atlantic Rim project for the balance of 2008 will be driven by progress of the planned project.

During the second quarter of 2008 Warren and its partners in the project began a fracture stimulation program in the existing 45 well Doty Mountain Unit. To date, six wells have been stimulated and two of the wells have been placed back on production for approximately three weeks. Although results from the program are still quite preliminary in nature, a valuation of the stimulation work is encouraging with dramatically improved gas and water production rates. Warren and its partners expect all six wells will be back on line in the next two weeks. If production results continue to show potential, stimulation work on additional wells will continue until all 45 wells in Doty Mountain have been treated.

Warren also experienced significant production growth from the Catalina Unit in the Atlantic Rim during the second quarter. Warren participated in the drilling of 33 producing wells in Catalina during 2007 and early 2008. Due to water injection capacity constraints in the unit only 24 wells are being produced currently of the 47 well total which includes the 14 wells drilled previously. Gross gas production for Catalina averaged approximately 21 million cubic feet per day in July. Warren is currently participating in the development of an additional 24 wells in Catalina. There are currently three drilling rigs active in the unit. Warren now owns 5.3% working interest in Catalina and expects this interest to increase to 17% as the project is developed.

Thank you and now I’d like to turn the call back over to Norman.

Norman F. Swanton

We’ll now take any questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from Leo Mariani - RBC Capital Markets.

Leo Mariani - RBC Capital Markets

I have a question here on some of those Sun Dog wells here. Can you give us a sense of when those wells were hooked up in terms of what was drilled last winter? Did those come on in stages during the second quarter, and how long have those things been producing, and what kind of inclined rates are you seeing on the production there?

Kenneth A. Gobble

We began putting those wells on early in April. They did come on in phases. Every couple days we were going ahead and turning on three or four wells trying to manage the production as it came on. We are seeing some very good rates out of a lot of the wells. Most of the big rates are right around the existing pattern of the 12 wells that had been there as we would have expected because of the dewatering. We are seeing some incline there of course. We are to date still somewhat limited on water injection capacity. They’re making a lot of water which is not bad news at all. I think that’s indicative of the reserves that are there.

Leo Mariani - RBC Capital Markets

You mentioned some of the facility work is underway right now. Any timing on when you kind of expect that to be completed and would you expect when your water injection capacity increases that you’d see further jumps in the production out there?

Kenneth A. Gobble

When the stips hit last March we had drilled six injection wells. We were only able to get four of those on line before the stipulations required us to leave the area as far as construction went. That work is ongoing now. Of course facility expansion because of additional drilling will be taking place probably until the stips hit again in March. But I would expect that as time goes by here and as construction continues to progress out there that we will continue to be able to increase water production not only from those wells that we put on in April from those 60 wells of last year’s program but even be able to hook up additional wells that we’re drilling now. So I guess what I’m saying is I think that infrastructure is coming. We’re not expecting it to take too much longer to give us additional water handling capacity, so I think as far as our progress on adding new production I think it should match pretty closely with our forecast.

Norman F. Swanton

Leo, I’d just like to make one further comment in answer to the other part of your question on what these types of wells were doing previously and back in when we started them in 2002. We have a the type curve we’re looking at which is why we’re so enthusiastic because these new wells are way above our type curve. But just apples to apples, as I recall the earlier wells came on making a lot of water about 50 mcf a day I would say back in 2002. Those have inclined to over 500 mcf a day. The new wells coming on didn’t come in on 50. Of course they went from low numbers to some making a million a day but I think on average they are over 200 mcf a day right now just starting off and I expect a strong incline from those numbers. So we have quite a dramatic difference between the original wells in Sun Dog and these new wells.

Leo Mariani - RBC Capital Markets

Jumping over to NWU you mentioned your production’s picked up there recently and you’ve got a couple of these horizontal wells on line which hopefully is going to continue to increase. You mentioned some facilities work. Where do you think your production’s going to be limited till you bring new facilities in? Do you have a higher capacity than you’re currently producing out there if you can get these next couple wells to increase when the water injection increases there and as you drill more wells?

Kenneth A. Gobble

Our overall capacity limitation in NWU will be gross fluid handling capacity and really what it looks like, we will be able to handle the additional program that we’ve got forecast now for 2008 which would be the three producers that we drilled and the two additional wells that we expanded.

Operator

Our next question comes from Irene Haas - Canaccord Adams.

Irene Haas - Canaccord Adams

Firstly, congratulations on a very strong performance from the Rocky Mountain coalbed methane. I’m sure you’ve been waiting for this to happen for a long time. Do you have any feel as to the decline rate and ultimately reserve per well that you might have in the Washakie Basin? And secondarily, can you spell out the timeframe for the installation of the new equipment in North Wilmington Unit, just precisely when you have to take the flare off and when the reinjection will occur?

Kenneth A. Gobble

Irene, as you know we do have a tight curve in the Atlantic Rim. These are very long life reserves is what we are expecting; somewhere on the order of approximately 20 years. As Norman mentioned, once we surrounded the 12 well pilot in Sun Dog with a significant number of additional producing wells, we were really expecting the wells to show some sign of decline after being on line and producing for approximately six years. And actually what we saw was that production actually increased. On a per well basis I think reserves especially in that area are going to be somewhere near a bcf per well. We’re seeing indications that there’s a good possibility that we could out-produce the volume metrics which most of the initial forecasts were constructed upon. Our tight curves have the decline starting in approximately three years after initial production; of course inclining for about a year, stable for about a year, and then starting to decline in the Atlantic Rim.

And then to answer your questions, I believe actually you are referring to the Wilmington Townlot Unit about the gas handling equipment and when we can get that installed.

Irene Haas - Canaccord Adams

Yes. I’m sorry.

Kenneth A. Gobble

We have the equipment available. A good portion of it is already out there in the area. It has been purchased. And I believe we can execute construction and installation of that equipment very quickly once the permits have been processed. I would very much hope that that is all completed in the fourth quarter, but Irene it is completely dependent on when we receive the permits from the AQMD.

Irene Haas - Canaccord Adams

Can you educate me a little bit? To reinject gas, what precisely do you need in terms of equipment and how much does it cost?

Kenneth A. Gobble

Primarily all we need is a compressor. Of course it would need to be a high pressure compressor because we would have to match the receiving reservoir pressure with the surface compressor to get it down hole. I don’t have a per unit cost in front of me but Irene keep in mind that the volumes we’re talking about are really quite small. We’re talking only about most likely somewhere 400 to 800 cubic feet per day. So in the overall scheme of things and our operating expense side it would be minimal, practically insignificant.

Irene Haas - Canaccord Adams

So if everything goes well, you’ll be injecting gas and basically you wouldn’t even be using the flare beginning 2009 unless there’s an emergency. Did I get it right?

Kenneth A. Gobble

That’s exactly right. The plan that we put forth to the South Coast Air Quality Management Division was to reduce our overall emissions and to do that we really would like to eliminate use of the flare on a daily basis.

Irene Haas - Canaccord Adams

So there’s no more discussion of the high tech flare?

Kenneth A. Gobble

Oh no. We’ll still install the high tech flare but it will only be used as a backup to reinjection.

Operator

Our next question comes from Duane Grubert - CRT Capital Group LLC.

Duane Grubert - CRT Capital Group LLC

A little bit about the frac work at Doty Mountain. Maybe a little on the size of the fracs and really what you’re trying to accomplish. Is it more oriented towards faster dewatering or is it really a rock mechanics thing where you’re expecting better gas production and whether or not there’s something different about Doty than the rest of the program up there that would suggest that you’re going to frac or not frac other parts of the program?

Kenneth A. Gobble

Duane I would like to attack the last question first. I believe that production histories have indicated that the coal is somewhat tighter in the Doty Mountain area, has less permeability than when we compare it to say Catalina or Sun Dog. Our determination of whether to fracture stimulate in other areas will always be dependent on the present value of the investment of what it costs to stimulate and whether that is actually a wise return on investment to make that determination of whether we fracture stimulate or not. As we continue to drill wells and have good comparisons in units, say Catalina to Sun Dog, we have much better data available to us to help us make those decisions.

As far as the types of jobs that we’re pumping, we’re looking at about 70 quality nitrogen jobs with roughly somewhere on the order of 30,000 to 50,000 pounds of [inaudible]. Keep in mind that these wells have already been perforated so we’re unable to multi-stage. So really not extremely large jobs at all.

Duane Grubert - CRT Capital Group LLC

In your release you made some comments about the ASP thinking going forward and there’d be some sensitivity work done, etc. I’m under the impression that your body language suggests that it’s very unlikely that we’re going to hear you say, “We changed our minds.” So I’m curious, what would it take to have you make a leap of faith and get something going before some of that work is done, maybe in terms of accelerating the infrastructure build-out and stuff like that?

Kenneth A. Gobble

In addition to completing our lab work that our contractor Surtech is working on currently, we will also run at least some type of pilot project for real world results prior to going full field. And of course it’s all going to be determined on commodity pricing environment versus the investment versus incremental recoverable oil. Once we have the full lab work done we’ll go to the pilot stage which could take a significant amount of time, potentially a year or longer, and we would like to see those results. Of course we can be in the planning mode but as far as actually beginning to install and construct the necessary infrastructure, we’re still quite a ways out.

Duane Grubert - CRT Capital Group LLC

With the expansion of activity particularly in the Atlantic Rim, are you seeing any well cost learning curve benefits either on cost or overall completion?

Kenneth A. Gobble

In this environment, as you’re well aware Duane, the cost of services continues to increase year-over-year. Steel prices are up significantly this year, so all of that has a big effect on well costs of course. We are making some strides in design work and our knowledge that typically offsets those costs to some degree, but unfortunately costs of goods and services continue to outstrip the improvements that we’re making on efficiencies. One thing I would point out is that in 2007 and 2008 we had a very, very severe winter in the western slopes of the Rocky Mountains which significantly impacted costs. I think it would be unusual to expect that winter again this year so to be honest with you, those are the three things that I see having the biggest impact on the cost of development out there moving forward: Cost of goods and services being primary; next would be weather conditions believe it or not; and then thirdly I would say that improvements in project design and efficiencies as we continue to develop.

Duane Grubert - CRT Capital Group LLC

Finally to clarify, you said you had six wells that needed to be completed that were under the footprint of the big neighbors rig. Can you walk me through that? Maybe I’m confused.

Kenneth A. Gobble

Actually those wells were completed during the second quarter.

Duane Grubert - CRT Capital Group LLC

So they’re already completed. Are they on production or available to be produced once your constraints -

Kenneth A. Gobble

They’re on line. Our producing well count out there is continually being adjusted day-to-day Duane depending on our gas production. Some of those six wells were injectors, I would also state.

Operator

Our next question comes from Mark Lear - Sidoti & Co.

Mark Lear - Sidoti & Co.

In terms of the gathering system in the Atlantic Rim, it looks like you are kind of getting up to capacity there and your drawing a lot more wells in the Sun Dog. Do you guys anticipate having everything in place to take all that extra gas?

Kenneth A. Gobble

Yes, I believe so. Our goal would probably be to continue to invest in infrastructure to a point where our infrastructure is as close to full utilization as possible. And of course when you’re working on such a large development program, infrastructure expansion is an ongoing program. So I guess Mark to answer your question as best I can, I can tell you that we do have a gas forecast and a water production forecast out there; we are developing infrastructure to match that forecast. Keep in mind that we’re still very much early on in this project and as we continue to develop wells, get more production history, we will continue to adjust that forecast and therefore continue to adjust our infrastructure need forecast to hopefully more closely match our needs.

Mark Lear - Sidoti & Co.

It looked like your realized gas prices came in a little bit higher than what even CIG averaged on the quarter. Do you have any physical delivery contracts or hedges in place there?

Kenneth A. Gobble

No, not at all. I believe it also included some profits in our gathering system out there.

Operator

Our next question comes from Jack N. Aydin - KeyBanc Capital Markets.

Jack N. Aydin - KeyBanc Capital Markets

Tim, you mentioned that your borrowing base will go up in October. Are you telling us that the mid-year reserve have gone up and if that is the case, could you shed a little color on it?

Timothy A. Larkin

Sure Jack. In our year-end reserve report since we didn’t have those Sun Dog wells on line at year end they were not included as proved reserves or PDPs and therefore they didn’t get calculated into the overall borrowing base. Additionally we’ve seen some pricing improvements since year end although the last two weeks have kind of erased some of that. So it was kind of a combination of the additional PDPs from Sun Dog plus improved pricing that leads management to believe that our borrowing base should increase.

Jack N. Aydin - KeyBanc Capital Markets

Ken with the Atlantic Rim, how is the relationship with Anadarko? What do you hear with your dealing with them regarding their interest over there?

Kenneth A. Gobble

We still have a very strong relationship with Anadarko. I continue to be reassured by the Anadarko team and their management that their commitment to the project is very strong and that it fits well with their realigned company focus on the plays that they are exploiting.

Jack N. Aydin - KeyBanc Capital Markets

Norm what do you hear in terms of assets/reserves changing hands in the West Coast? Are these transactions that took place in the past couple of months, what kind of pricing do you see people changing hands or reserve changing hands?

Norman F. Swanton

It depends on the reserves Jack. Some offshore reserves changed hands at a lower price and some onshore reserves traded at a premium from what I’ve seen. I think it depends on the nature of the reserves. If you’re talking about reserves in California, you’ve got very strict environmental issues and offshore can be a challenge. Our focus has been as you know onshore exclusively US so we’re keeping an eye on it, but I would say overall it’s been very encouraging in terms of the pricing.

Jack N. Aydin - KeyBanc Capital Markets

Any asset change hands in your area WTU and North WU?

Norman F. Swanton

Well they can’t be in NWU since we own 100% of one and 90% of the other. But I think that the one transaction Pacific Energy sold their interest in the Wilmington field to Occidental Petroleum but other than that I haven’t seen any other things change hands.

Operator

Our next question comes from David Tameron - Wachovia Capital Markets, LLC.

David Tameron - Wachovia Capital Markets, LLC

In Catalina I know you get a bigger working interest. What’s the trigger for that to go from 5% to 17%?

Kenneth A. Gobble

David as more wells are drilled, the participating area expands. As a participating area expands, it covers more acreage that Warren has an interest in.

David Tameron - Wachovia Capital Markets, LLC

So it’s just well by well it increases? There’s no magic level it has to reach?

Kenneth A. Gobble

Not at all. It’s merely the acreage that’s developed.

David Tameron - Wachovia Capital Markets, LLC

Where are you at versus infrastructure pipeline capacity takeaway coming out of the Rockies? Can you review what your firm transport is?

Kenneth A. Gobble

Actually we continue to rely on Anadarko for firm transport out of the Atlantic Rim project and to date even prior to Reps coming on line our gas moved every day.

David Tameron - Wachovia Capital Markets, LLC

And no current tightness in the takeaway?

Kenneth A. Gobble

As a company we have been constantly reviewing Rocky Mountain access to regional markets and we do have some concerns but I think there are several systems on the board now to be coming on line in the next couple of years. So David I think it’s safe to say that we are interested in at some point in the future once our volumes become significant in looking at options to get firm transport out of there. I would only add that to date we’ve been a bit reluctant because our volumes have been relatively small.

David Tameron - Wachovia Capital Markets, LLC

Jumping around on you here, the coalbed methane. I know you mentioned your type curve and I know you have one in your presentation but your peak rates, are you still hitting about 600 or 700, 550 or 600? What’s that number?

Kenneth A. Gobble

We have toned down our type curve to approximately 450 at max rate. I think we’re still right around in that area with approximately a bcf recovered on an 80-acre space.

David Tameron - Wachovia Capital Markets, LLC

I’m just trying to reconcile. You mentioned in the press release, you said Sun Dog wells are not hitting 500 a day?

Kenneth A. Gobble

Yes, 500 and change.

David Tameron - Wachovia Capital Markets, LLC

Is there some assumption there that as you drill more wells and dewater that you’re still comfortable with the run rate of 450?

Kenneth A. Gobble

Yes, but I would only qualify that David and say that our production history is quite small in area compared to the area we have to develop.

David Tameron - Wachovia Capital Markets, LLC

California. I’m real ignorant on this issue but as far as upcoming elections, any potential changes that could affect your legislative process? I’m not aware of what’s happening in the current upcoming election.

Kenneth A. Gobble

As you’re well aware I’m sure, there’s always talk about some type of federal windfall tax or state production taxes in California. So I would have to answer that there’s always a concern in that regard.

David Tameron - Wachovia Capital Markets, LLC

But as specific to California, any changes in the state government there?

Kenneth A. Gobble

Not that I’m aware of.

David Tameron - Wachovia Capital Markets, LLC

Steel rigs. I think Norman you mentioned that you guys are adding rigs. Can you talk about the availability of those rigs and maybe add a little bit different spec on your rigs than what’s being pursued by a lot of the shale players? But can you just talk about what that market looks like right now?

Norman F. Swanton

I’ll turn that to Ken.

Kenneth A. Gobble

Honestly David, in California we’re trying to run especially in the Wilmington Townlot Unit electric equipment and it’s pretty much built for site purpose. We run on skids because we’re so close wellhead wise. So that’s not considered competitive with the fleet say in any of the shale plays. And of course in the Atlantic Rim we’re using a much smaller class of rig there just to our drilling depths. So the things that you’re seeing in the Haynesville or the Marcellus or the Barnett expanding or the Woodford in Oklahoma, we’re not in direct competition for those drilling resources.

Operator

There are no further questions at this time.

Norman F. Swanton

I’d like to thank you all for joining us today and for you interest in Warren Resources. I hope I have conveyed to you how excited we are about executing on our operating plan and capitalizing upon the enormous potential in front of us for the balance of 2008 and beyond. Thank you and good day.

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Source: Warren Resources, Inc. Q2 2008 Earnings Call Transcript
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