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Warren Resources, Inc. (NASDAQ:WRES)

Q2 2011 Earnings Conference Call

August 9, 2011 10:00 ET

Executives

Norman Swanton – Chairman and Chief Executive Officer

Tim Larkin – Executive Vice President and Chief Financial Officer

Steve Heiter – Executive Vice President and Chief Executive Officer, Warren E&P

Analysts

Phil McPherson – Global Hunter Securities

Leo Mariani – RBC Capital

John Abbott – Pritchard Capital Partners

Operator

Good day ladies and gentlemen and welcome to the second quarter 2011 Warren Resources Earnings Conference Call. My name is Penny [ph] and I’ll be your conference moderator for today. At this time, all participants are in listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions). As a reminder this conference is being recorded for replay purposes.

I would now like to hand the presentation over to Mr. Norman Swanton, Chairman and CEO of Warren Resources. Please proceed.

Norman Swanton – Chairman and Chief Executive Officer

Thank you. Good morning everyone. Thank you for joining us for our Warren Resources second quarter 2011 financial and operating results conference call. We are conducting the conference call this morning from our Long Beach California Executive Office and with me is Steve Heiter, our Executive Vice President and the CEO of our operating subsidiary Warren E&P and Tim Larkin, our Executive Vice President and CFO is joining us from our New York City headquarters office.

Before I turn the microphone over to Tim to cover the financial results and Steve to discuss our oil and gas operations, I would like to briefly comment on our performance for the second quarter 2011 and the future direction of the company.

During the second quarter of 2011, we achieved a favorable resolution of our pending regulatory matters at the Wilmington Townlot Unit, our main oil producing Unit in California. These regulatory matters included approval of our first water injection permit issued under the newly adopted regulations of the California Division of Oil, Gas and Geothermal Resources and certification by the South Coast Air Quality Management District of our environmental document including approval of the related permits to increase oil processing capability to 5,000 barrels of oil per day at the WTU. Additionally, these permits allowed us to install best available control technology, including a clean enclosed burner, which eliminated gas flaring entirely.

Despite some start-up issues with our new drilling rig that Steve will discuss in more detail, our total oil and natural gas production for the quarter ended June 30, 2011 only decreased 1% to 430,000 net barrels of oil equivalent or BOE compared to the second quarter of 2010. However, production increased by 6% compared to the fail in first quarter of 2011.

Net earnings were $9 million for the second quarter of 2011 or $0.13 per diluted share. Additionally, as a result of higher oil prices, our oil and gas revenue increased 28% to $26.9 million for the second quarter of 2011 compared to $21 million in the second quarter of 2010 and $23.2 million in the first quarter of 2011.

Since the commencement of our 2011 horizontal and sinusoidal drilling program at the WTU in late March of 2011. The company sort of confirmed its shallow prude reserves as well as unproved oil reserves and seven potentially producible zones within the tar Ranger thermal formations at the WTU. This plant increased production and confirmed additional reserves will continue throughout 2011 and beyond.

Our geological, petrophysical and economic analysis supported by drilling resource to-date resulted in our discussion to increase 2011 capital expenditures by 18% to $70 million. This increase in capital expenditures includes leasing a second drilling rig to accelerate development at the WTU in 2011. And subsequently to move the rig to the NWU to commence horizontal sinusoidal drilling at the NWU in the first quarter of 2012. We also intend to perform a 3D seismic shoot over both of our units and the Wilmington field targeting the shallow as well as the deeper Ford (indiscernible) formations.

Since we have achieved our immediate regulatory goals and begin our 2011 drilling program at the WTU with our new drilling rig to be followed by a second drilling rig in September 2011. I feel confident that we will begin to see more consistent full scale production reserve growth in the Wilmington field during the second half of 2011 and for many years to come.

On the natural gas side of the business Anadarko and Warren were jointly successful to form a federal Mega-Unit and the Atlantic Rim Coalbed Methane project located in the Washakie Basin in Southwest Wyoming. The Mega-Unit covers all debts on 130,000 continuous acres and oil leases within the Mega-Unit would be held by production. The Mega-Unit requires a minimum of 25 gross 10.3 net wells we drilled each year for the next 10 years beginning in 2011.

Even though we have not drilled wells for the past two years in the Atlantic Rim project, our single and Tuesday’s fractious stimulations and well optimization programs increased our natural gas production for the second quarter of 2011 by 7% to 1.24 billion cubic feet of gas equivalent compared to the second quarter of 2010. Additionally, we owned 80,000 net acres in the Washakie Basin below the CPM play which is prospective for Niobrara oil development. We have commissioned a regional geological study in the Niobrara which should be completed in 2011. Our liquidity position is strong. We have had most permitting and rig issues behind us and I believe that both our near-term and long-term outlook has never been better.

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

Tim Larkin – Executive Vice President and Chief Financial Officer

Thanks Norman. Before I discuss the company’s financial results released earlier today, I would like to remind everyone 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 10-K and 10-Q, other periodic filings with the SEC and our press releases

As Norman mentioned, we had strong second quarter and we’re excited about the balance in 2011 and beyond. Our cash flow from operations continues to be solid and we’re in a strong liquidity position. As of June 30, 2011 we have $50.5 million available under our senior credit facility. We have now paid down $45.5 million of debt under this facility over the last two years months.

Additionally, we’ve acquired an oil drilling rig for $14 million which includes assembly costs. This rig was specifically manufactured for onshore drilling operations in Southern California.

Today we reported net income of $9 million or $0.13 per diluted share and adjusted net income of $7 million or $0.10 per diluted share excluding gains from hedging activities of $2 million. Additionally during the quarter we generated $12.3 million of cash from operations. Also, our oil and gas production was 430,000 barrels of oil equivalent for the quarter or 470,000 of barrels of oil equivalent per day.

Production from our two oil fields in California totaled 224,000 net barrels during the second quarter, a 7% decrease from the 241,000 net barrels produced during the same period in 2010. Additionally, natural gas production primarily from our Atlantic Rim project in Wyoming was strong and overall natural gas production increased 7% to 1.24 net billion cubic feet during the second quarter compared to 1.16 net billion cubic feet during 2010.

The average realized oil price for the second quarter of 2011 was $97 per barrel compared to $70 per barrel during the second quarter of 2010 an increase of 40%. Our second quarter Wilmington blended oil differential from NYMEX pricing was approximately $5 per barrel. Our average realized gas price for the second quarter was $4.13 per Mcf compared to $3.62 per Mcf in the second quarter of 2010.

Under our current contract with Conoco Phillips which expires in July 2012, the company sells its oil at a price of 87% of NYMEX for the first 1,800 barrels of oil per day and Midway Sunset plus a $0.85 bonus of for the balance of our production. We currently produce approximately 2,500 net barrels of oil per day. Midway Sunset is currently selling at a premium of $5 to NYMEX.

Also during the second quarter, we incurred a realized loss from derivatives of $3.4 – I am sorry realized loss from derivatives of $3.4 million and an unrealized non-cash mark-to-market gain from future derivatives of $5.4 million. Among our oil and gas hedges, the company owns a $61.80 NYMEX oil swap for calendar year 2011 at 840 a day 165,000 total barrels from July 2011 to December 2011

The company also owns a NYMEX oil costless collars for calendar year 2011 with a floor price of $70 from June 1, 2011 to December 31, 2011 or 129,000 total barrels and a ceiling price of $101 for 700 barrels of oil per day in which the ceiling of $101 commences September 1, 2011 and December 31, 2011 or 85,000 total barrels. Warren also owns January 2012 oil coal options with strike prices between $120 and $125 per barrel for 500,000 total barrels. This should partially offset derivative losses that may result if oil prices increase.

Approximately 50% of our forecasted 2011 natural gas production is hedged with either NYMEX swaps at approximately $4.50 per Mcf and costless collars with floor prices between $4.00 and $4.25 per Mcf and ceiling prices between $5.03 and $6.28 per Mcf. As a result of improved oil prices, oil and gas revenues for the second quarter increased 28% to $26.9 million compared to 2010.

Our total operating expenses increased 19% to $19.2 million during the second quarter of 2011 compared to 2010. Lease operating expense increased 29% to $8.7 million due to increased California at Warren taxes and increased transportation cost associated with our Wyoming natural gas. Anadarko now sells our gas downstream at a higher price than CIG firm and charges us transportation fee. We expect oil LOE’s to average approximately $23 per net barrel in 2011.

Depletion, depreciation and amortization expense for the second quarter increased 33% to $6.8 million compared to the second quarter of 2010. DD&A was $15.92 per BOE during the second quarter of 2011 compared to $11.84 per BOE during the second quarter of 2010. This increase in DD&A on a per barrel basis resulted from higher estimated future development costs as of December 31, 2010 compared to 2009.

General and administrative expense decreased 14% to $3.6 million during the second quarter of 2011. This decrease resulted from a reduction of $400,000 to incentive compensation accrual recorded during the second quarter of 2011 compared to the same period in 2010. Additionally, stock option expense and legal expense decreased $400,000 and $200,000 respectively. This decrease was offset by an increase in salary expense of $400,000 for the quarter.

Interest expense decreased 12% to $774,000 as we continue to pay down the outstanding balance on our credit facility as previously mentioned. Net cash provided by operating activities was $12.3 during the second quarter of 2011 compared to $9.7 million during the second quarter of 2010.

Our forecast to 2011 capital budget is $70 million. This includes expenditures of approximately $36 million for drilling, 18 producing and two injection wells in our WTU oil field in California and $14 million for related infrastructure costs in our WTU and NWU oil fields.

Our California capital expenditure budget also includes $5 million for expenditures related to our new drilling rig and $3 million for 3-D seismic shoot of our California properties. Additionally, we forecasted $10 million for drilling gas wells and $2 million for infrastructure cost related to our Atlantic Rim project in Wyoming. In order to form the Mega-Unit which protects about approximately 113,000 gross acres in our Atlantic Rim project, the company has agreed to drill 25 gross and 10 net wells in 2011 and future years. This acreage is perspective for both coalbed methane natural gas and Niobrara oil. We do not plan to drill Niobrara oil well in 2011.

Our borrowing based under our credit facility is $120 million. The next re-determination is scheduled for October 2011 due to our strong liquidity position and lender’s fees associated with increasing our borrowing base, we did not ask our lenders for a borrowing base increase for our last two redetermination.

As operator of the WTU and NWU oil assets in California and co-joint venture of the Atlantic Rim project with Anadarko, the company has the ability to modify its capital budget as commodity and financial markets change.

We reported third quarter and full year 2011 production guidance in our press release disseminated this morning.

Now let me turn the call over to Steve who will provide you with a brief operational update. Steve?

Steve Heiter – Executive Vice President and Chief Executive Officer, Warren E&P

Thank you, Tim. Now I’d like to update Warren’s operational details. During the second quarter of 2011, we produced a total of 430,000 net BOE consisting of 224,000 net barrels of oil from our Wilmington oil field and 1.24 net Bcf of natural gas from Wyoming properties.

As reported last quarter, Warren’s new drilling rig is now fully assembled and operational in the Wilmington Townlot Unit. Rig start-up issue were problematic in the second quarter resulting in only five wells being placed on production this year when eight wells were typically have been drilled and placed on production during this timeframe. Rig start-up experts have inspected our rig and believe that are significant, mechanical and electrical issues have been resolved.

We spotted the first well of our 2011 drilling program as sinusoidal horizontal well in the upper terminal J-Sand formation on March 28. The well was placed on production on April 21 and continues to produce about 70 barrels of oil per day with no decline after three months on production. The second well was drilled on two to test potential tar D-1A reserves in a new fault block. The well was placed on production on May 2, and a 30-day initial production rate was about 190 barrels of oil per day. The third well was drilled with the Ranger formation, but was suspended due to casing problems. A rework of the well was planned later this quarter. The fourth well, a Southwest tar well had a 30-day IP [initial production] of 180 barrels of oil per day. Our fifth well was drilled to the Ranger formation due west of the central site after encountering several drilling problems the well was placed on production on July 26 and is currently producing from 70 to 90 barrels of oil per day.

Yesterday, we ran the pump in our sixth well and other tar well in the new fault block where the company currently has no reserves booked. The well is on production and will be tested later this week. We are currently negotiating to bring in a second drilling rig to WTU which will allow us to drill a total of 20 wells in 2011 instead of 16 wells in the original 2011 plan.

The balance of the 2011 drilling program will consist of sinusoidal horizontal wells in the Ranger and upper terminal formations as well as additional horizontal tar wells and our first deeper horizons Ford well. Water injection wells have been or converted as DOGGR permits are obtained throughout the remainder of the year.

On June 20th we received approval from the DOGGR if you commence water injection into WTU 2,163 our tar injection well drilled in 2010. Current injection rate is approximately 10,000 barrels of water per day and a small reservoir pressure increase as already been seen which will ultimately increase over our tar production. As a result of this approval, we are no longer hauling water from the WTU to our other unit NWU and we have no WTU wells shut in for water control. We have several additional water injection applications pending with the DOGGR and expect approvals later this year.

As earlier reported on July 19, 2011 the AQMD certified the company’s CEQA documents and issued all of the related permits including gas handling equipment. These equipment upgrades will increase the Company's oil processing capability to 5,000 barrels of oil per day at the WTU. These permits allow us to install several features of best available control technology equipment including a clean enclosed burner, new heater/treater and gas injection compressor. A clean enclosed burner was installed last week and is currently in operation.

We have committed $6.7 million of capital to upgrade the production and water handling facilities in the company’s north Wilmington unit. This work should be finished in late 2011 in order to accommodate anticipated increased oil production from NWU when drilling activity is resumed in early 2012. In addition, we are in the process of acquiring a necessary Townlot around our central facility or our second drill site for more than 50 wells in our development plan.

On June 20, the US Bureau of Land Management approved the new Spyglass Hill Unit in the Atlantic Rim. The Spyglass Hill consists of approximately 113,000 gross acres and includes the areas previously committed to the Doty Mountain, Sun Dog, Jack Sparrow and Brown Cow Units, as well as all additional leases in the southern portion of the project acreage. This new unit will allow more efficient development and utilization of existing water and gas transportation infrastructure along with better protection of leases and acreage. The Catalina Unit remains unaffected by the formation of the Spyglass Hill Unit.

Warren is currently participating in the drilling of 25 gross or 10 net new wells in the Spyglass Hill unit and will participate in 2 gross or 0.3 net new wells in the Catalina Unit in 2011. As of today, 4 of the 25 Spyglass Hill unit wells have been drilled and cased.

We continue to evaluate the potential of Warren’s Atlantic Rim acreage for Niobrara oil development. We have commissioned the regional geologic study of the Niobrara which will be completed in early September. We currently have no plans to drill a well in 2011, but after conclusion of the study we will determine the best options for development.

Thank you for participating today, and now I will turn the call back to Norman.

Norman Swanton – Chairman and Chief Executive Officer

Thank you, Steve. Operator, we’ll now take questions.

Question-and-Answer Session

Sure. (Operator Instructions) Our first question will come from the line of Phil McPherson with Global Hunter Securities. Please proceed with your question.

Phil McPherson – Global Hunter Securities

Hey, good morning gentlemen.

Norman Swanton

Good morning Phil.

Phil McPherson – Global Hunter Securities

Nice job on the quarter in the permits. A few questions operationally, is the Ranger well, it seem like both of the Ranger wells you had some operational issues. Is there something there as far as the drilling that is real different, or something that you’re learning to avoid the future kind of Ranger issues?

Steve Heiter

Phil we had two issues when we’re drilling the Ranger wells. One of them had to do with some theories we had on the drilling rig which caused downhole problems. We had great failures. We also had several top drive failures and that resulted in some stock pie and downhole problems. So, those were regulated. We have – we believe we have taken care of those. All those orders have been replaced and as I mentioned we had a rig inspection company come out and do a thorough inspection. It’s the same company that expects most of the offshore rigs that – all the offshore rigs actually are Transocean owns and a lot of other major rig owner. So, we believe the rig is in good shape and so that caused a couple of the problems. The other one of the problems was that we’re drilling at the high angle through the tar which is a little lower pressure and that caused them all problems and we have taken care of those. So, we think we’ve addressed those problems we have drilled successful Ranger well. Since we encountered those problems. So, we did some pretty thorough investigations and we think we’re back on track.

Phil McPherson – Global Hunter Securities

And Steve when you mean this high angle energy going through the tar, are you saying like – you’re almost like losing circulation because of the low pressure?

Steve Heiter

That’s one of the problems, yes.

Phil McPherson – Global Hunter Securities

Okay, okay.

Steve Heiter

At tar, as you know at tar going 93 feet shale, but when you’re drilling at a high angle it can be as much as 5 or 600 feet deep. And so you have a lot more of that low pressure exposed to your drill pipe.

Phil McPherson – Global Hunter Securities

Gotcha, gotcha. And as far as operating cost Tim, could you say 20 or $23 for the balance of 2011?

Tim Larkin

$23.

Phil McPherson – Global Hunter Securities

23.

Tim Larkin

Yeah.

Phil McPherson – Global Hunter Securities

And do you think that’s a number that can be improved upon going at further outers that can be kind of a new stand?

Tim Larkin

Well, I think we can probably improve upon that in the later years. We’ve kind of – we’ve been aggressively P&A in wells in the near-term and we hopefully once we P&A the wells that are outside the central facility, those cost would go away. But it’s definitely in the future, we think we can get that number down a little bit.

Norman Swanton

Yeah, I can add to that two, in addressing to the P&A, we have replaced or upgraded every tank that we have, there is about 12 tanks at WTU and NWU. And some of that was expense and some was capital and they’re fully replaced. And some of those tanks have been cleaned up and repaired which was all expense. So, that’s a one-time expense still, and that was pretty big number.

Phil McPherson – Global Hunter Securities

And the reason that you were expensive was putting into the CapEx?

Tim Larkin

Because it’s just repaired. It’s like a chance. If it was upgraded or replaced then that was still included in the capital budget.

Phil McPherson – Global Hunter Securities

Okay, great. And as far as the second rig, I assume that you’re looking at a variety of rigs and what’s your kind of your choices out there to avoid of kind of bringing a rig in the – you’re going to have the same kind of issues with this to start up reserve. Is there availability right now?

Steve Heiter

Well there is a lot of factors that went into the study that added second rig and Norman mentioned a couple of them. And the other one is to make sure we secure a rig for NWU five or six months from now when you’re ready and the company is just providing the labors for our drilling rig had a rig come available. And it’s the well respected company in California and we’re currently finalizing the contract and it’s coming off in other job. We’ll have the same people who is on the other job and it’s a good rig. And the reason when I’m getting it to late September is because we have the order of top drive and they’re not readily available. It will be in sometime in September. So, that’s the approximate timing when we expect to start-up mid to late September.

Phil McPherson – Global Hunter Securities

Great. And with the second rig coming and keeping it at NWU, would you look it like 2012 rig count, I mean a well count of like – is 24 a good starting point or maybe a little more?

Norman Swanton

For both units?

Phil McPherson – Global Hunter Securities

Yeah, for total wells drilling in both unit with two rigs running?

Norman Swanton

That’s probably pretty close, between 20 and 30 I would guess.

Phil McPherson – Global Hunter Securities

Okay, that’s good. And last and I’ll jump off, with you guys Wyoming CapEx, do you have any control over the number or is it one of these things that you basically have to decide if you want to participate or not participate?

Steve Heiter

In the – despite last year, we’re pretty much obligated to participate in the 25 to keep drilling this. With the Catalina Unit we have our choice of participating, we’re not participating.

Phil McPherson – Global Hunter Securities

And is there ever a point where you would decide to take the capital and divert it from there into the more oily stuff, or is this right now you’re permanently trying to keep production flat there?

Steve Heiter

Well we did have an opportunity to participate in a much larger number in Catalina. We elected not to, we elected only to participate in the two that thought where appropriate for us.

Phil McPherson – Global Hunter Securities

Great, I appreciate it guys. Thanks for all the color.

Steve Heiter

Thank you.

Norman Swanton

Thanks Phil.

Operator

Our next question comes from the line of Leo Mariani with RBC Capital. Please proceed with your question.

Leo Mariani – RBC Capital

Hey good morning guys.

Norman Swanton

Good morning Leo.

Tim Larkin

Good morning Leo.

Leo Mariani – RBC Capital

Just wanted to touch a bit in what you guys said about your oil contract with Conoco, I guess that expires in middle of 2012 here. I guess there is been a sort of an other party recently that kind of renegotiated a contract out there in California given the higher prices. Just wanted to think you guys were pursuing any type of renegotiation in that deal this time.

Norman Swanton

You are considering that Leo.

Leo Mariani – RBC Capital

Okay. I guess just jumping over to your oil production here, just wanted to kind of clarify some of your prior comments in the call, so I guess it sounds like pretty recently that at this point you don’t have any wells shut in at WTU, just wanted to make sure that’s correct. Is that happened sometime here in I guess in July or August? Is that right?

Norman Swanton

We have no wells shut in WTU, but the story of that number is exact day, so at the beginning of the year we started off, we’re between 2 to 300 wells they shut in and then we brought on some of that and near the end we had about 100 wells shut in and then we got tar extraction well aligned. So, it was probably early June, that’s what I guess sometime around there.

Leo Mariani – RBC Capital

Gotcha, okay. And I guess we’ll definitely expect to see production sort of increase in the second half of the year here. I wanted to clarify your comments about gas reinjection. Are you guys currently reinjecting gas, I guess you talked about installing a flare there. And what is the plan for reinjecting gas.

Norman Swanton

We have already installed a clean enclosed burner that replaced this deal clear. That’s gone. We get that last week assume we get (indiscernible) we had the flare already purchased and ready to be installed for that stock to burner, sorry yeah clean enclosed burner which is not of flare, our replaced deals were. And the next step will be to install the heater/treater – the new heater/treater so we end up with two. And that’s about four to six month process to go through the foundation permits and get the necessary civil permits to get that installed. We already owned the heater/treater considering here for quite a while and we’re ready to install it. The gas injection compressor was also approved as part of that package. And we’re going down parallel path of gas injection and gas sales and that’s where we’re at right now. We do not have approval from the Division of Oil and Gas right now to inject gas into a well. And that permit is pending and so that’s why we’re going down parallel path.

Leo Mariani – RBC Capital

Gotcha. So, you see parallel path, I guess you talked about gas sales remain, hey this is something that can happen in 2012?

Norman Swanton

No, it’s probably an 18 month to 24 process. We have been working with the appropriate agencies to go down that path and we’ve submitted the applications and we’ve developed the timeline and as an 18 to 24 month process to get approvals and install the equipment. And we started a couple of months ago.

Leo Mariani – RBC Capital

Gotcha, okay. With respect to your 3-D seismic shoot that you guys talked about it WTU, can you just give us a sense of purpose of the shoot which you guys hope you accomplish with the new treaty there?

Steve Heiter

Well, a couple of things that can help us with. First of all the Ranger is pretty channelized and all the drilling at the NWU is the Ranger. And obviously we also have Ranger, the WTU that we’re drilling now. So, it can help us with the Ranger, but the primarily focus is the deeper in the Ford and the shift formations that will tell us much more about the structure and that’s the main purpose for the stockers. But it also helps us with the shale.

Leo Mariani – RBC Capital

Gotcha, okay. I guess just jumping over to the Niobrara, I guess you guys originally talked about doing it well here in the second half of the year instead of the guys that are undertaking at the geologic study. Could you just give us a little color as to kind of why it started to go, the study routed the post drill wells there?

Norman Swanton

Well there have been a lot of wells drilled outside our acreage as you know down in Colorado and few other places. Some with great success and some with great poor success and rather than just finally jump in and spend capital on a well, we decided to take the three or four months. We’ve interviewed several local geological companies in Wyoming. We selected one and there is another month before it’s six weeks they’ll be finished with the study. And it will give us a better idea of how to develop the Niobrara and whether or not we ought to bring in partners and we would like to get a better feel for what we have and what’s been done around us and we don’t have that right now. And we didn’t think it would be appropriate for us to jump in and spend capital without little more knowledge.

Leo Mariani – RBC Capital

All right, thanks guys.

Norman Swanton

Thanks Leo.

Steve Heiter

Thanks Leo

Operator

Our next question comes from the line of John Abbott with Pritchard Capital Partners. Please proceed with your question.

John Abbott – Pritchard Capital Partners

Good morning.

Norman Swanton

Hi John

Steve Heiter

Hi John

John Abbott – Pritchard Capital Partners

Most of my questions have already been answered. I just have one quick question, could you talk a little bit more about the Ford formation and what’s your expectations as would it be more gas or would it be – are you still expecting oil, what are your specifications for the Ford?

Steve Heiter

Well we’re hoping to get both. One of the reasons for the excitement of the approval of the AQMD permit is that it allows us to produce and dispose at more gas which we expect from deeper. The primary purpose for the deep is oil, but it’s going to have quite a bit of associated gas which we happen to do something with. So, we expect more.

John Abbott – Pritchard Capital Partners

All right and do you know any drilling results in the Ford formation currently?

Steve Heiter

Do not recently – I mean a lot of wells drilled before 30, 40 years ago, we have all that data.

Norman Swanton

And it’s never been water flooded John.

John Abbott – Pritchard Capital Partners

I understand. Thank you very much.

Norman Swanton

Thanks John

Steve Heiter

Thanks John

Operator

(Operator Instructions) Our next question comes from the line of (indiscernible) with Sidoti & Company. Please proceed with your question.

Unidentified Analyst

Good morning guys.

Norman Swanton

Good morning JB.

Steve Heiter

Good morning JB.

Unidentified Analyst

A quick question on the water injection permit thing, there is your guidance for the remainder of this year, does that include the additional three water injection site, you said you needed?

Norman Swanton

Yes.

Steve Heiter

Our original production plan included four injection wells that’s correct. Well we didn’t anticipate the tar well to be – to take as much as large it’s taking. So, that takes the place for about three wells with what is taking now and so that was great result for us and that’s why we don’t have any production showed in right now. We anticipate at least one or maybe a couple more approvals this year. The Division of Oil and Gas has accelerated there, reviewed an accrual process. And we have gotten some pretty good indications from them after its couple of meetings that they’re going to be improving these at a much faster pace. So, we expect at least one, maybe two more. Another tar well to the Northwest and hopefully Ranger well.

Unidentified Analyst

Okay. And then your drilling plans for next year, how many do you need next year to do what you guys want to do?

Steve Heiter

Well we get these Ford that have planned for this year. We may – depending on our growing results, we may have a little bit of production shut in from the higher cut wells, but we wouldn’t be losing that much of oil production. Because we do have some high water cut well shut producing now that we could shut in. But….

Norman Swanton

More injections for the next year….

Steve Heiter

Well probably two or three more for next year I would guess.

Unidentified Analyst

Okay. And on the new Ranger that you guys just did that’s coming in at 70 to 90, is that within what you guys have modeled, are you guys happy with that number or are you looking for more once you get the some of the issues resolved.

Steve Heiter

We expect that the Ranger wells, we’re going to have some Ranger wells that are going to produce more than necessary. We had a Ford travel pack again on this well and are working on that. And we had some very positive reservoir results as we’re drilling this well with respect to picking up another location or two. The Ranger looked a lot better where we drilled this well than anybody anticipated. So, we’re pretty excited about it. We just need to resolve our completion issues which we think we’re on the way to do it.

Unidentified Analyst

Okay. And the two Ford wells that you’re going to be drilling this year, is that – are you go to be able to process for 3-D before you drill those or you guys, are you drilling that ahead of the 3-D processor?

Steve Heiter

Now we’re drilling ahead of the 3-D processors. The reason we’re going ahead with the 3-D at this time is because the company seems to have its future available to have a slot open in November. And after that they’re going up to North Dakota and they don’t know when they’ll be back. And this is the company that did the chutes Down Ocean, Boulevard and Long Beach just recently until there a lot of experience with doing it in this environment. So, that’s why we’re accelerating that at the end of this year.

Unidentified Analyst

Okay. One last one, on the new fault block in the tar, you guys have had some good results added there. What’s kind of the potential there. Can you add more locations or is that kind of still within the 20 or so tar locations you think you still have left?

Steve Heiter

Well it’s going to add some of the original DI. I don’t remember how many we add on originally, but with this second well and the log looking as good as it did, I believe that we could have three or four more of the locations I think the number has been told in that fault block.

Unidentified Analyst

Okay, that’s great. Great, quarter, thanks guys.

Norman Swanton

Thanks (indiscernible).

Operator

At this time we have no additional questions. I would now like to hand the conference back over to management for closing remarks.

Norman Swanton – Chairman and Chief Executive Officer

I would like to thank you all for joining us today and for your interest in Warren Resources. Thank you and good day.

Operator

Thank you for attending today's conference. This concludes the presentation. You may now disconnect and have a great day.

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Source: Warren Resources' CEO Discusses Q2 2011 Results - Earnings Call Transcript
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