Warren Resources' CEO Discusses Q4 2011 Results - Earnings Call Transcript

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 |  About: Warren Resources, Inc. (WRES)
by: SA Transcripts

Warren Resources Inc. (NASDAQ:WRES)

Q4 2011 Earnings Results Conference

March 6, 2012 10:00 am ET

Executives

Norman Swanton – Chairman and CEO

Timothy Larkin – EVP and CFO

Stephen Heiter – CEO, Warren E&P, Inc

Ronald Morin – EVP, Warren E&P, Inc

Analysts

Leo Mariani – RBC Capital Markets

Phillip Jungwirth - BMO Capital Markets

John Lowe - Sidoti & Company

Raymond Deacon - Brean Murray, Carret & Co

Jack Aydin - Keybanc Capital Markets

Operator

Good ladies and gentlemen and welcome to the Fourth Quarter 2011 and Full-Year Warren Resources Earnings Conference Call. My name is Jasmine and I’ll be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of today’s conference. (Operator Instructions). As a reminder this conference is being recorded for replay purposes.

I’d now like to turn the presentation over to our host for today, to Mr. Norman Swanton, Chairman and CEO. You may proceed, sir.

Norman Swanton

Thank you. Good morning, everyone. Thank you for joining us for our Warren Resources fourth quarter and full-year 2011 financial and operating results conference call. We are conducting the conference call this morning from our Long Beach California Operations Headquarters.

With me is Steve Heiter, and Ron Morin, our CEO and Executive Vice President respectively of our principal subsidiary, Warren E&P, in California and Tim Larkin, our Executive Vice President and CFO. He is joining us from our New York City Office.

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

As you will hear in more detail from Steve and Tim, we had an excellent operational financial year in 2011. First of all, we are in a strong financial position, thanks to our continued drilling success in California. As a result of drilling 17 new oil wells in California, our proved oil reserves increased by 46% during 2011 to 15 million barrels of oil. Assuming $80 per barrel average realized oil prices in California, although current Midway Sunset pricing is out in $10 a barrel, we anticipate that the 9 Tar formation wells drilled in 2011 will achieve payout in approximately one-year.

The nine first ever Ranger and Upper Terminal formation sinusoidal wells drilled in 2011 and to in 2010 should payout in one to two years. Estimate ultimate recoveries of 100,000 to 200,000 barrels of oil per well are expected.

Importantly, we gained essential knowledge to advance the Ranger and Upper Terminal oil reservoirs concept stage to full field development. As a result of the success of the 2011 drilling program, Warren exited 2011 and over 33,300 barrels of oil gross at the Wilmington Townlot Units. With an additional – and with additional 2012 drilling of producers and water injectors, should allow for significant increased production and reserves in future years.

While growing our oil production and reserves at the WTU and NWU are our top priority, we are now in a position to consider attractive acquisitions in basins where we can execute on our advanced horizontal drilling expertise and profitably grow more oil production and oil reserves.

We had water injection permitting challenges in 2011, but we rose to the task and most of those issues are now behind us. Additionally, to protect 2012 cash flow we have in place $90 Brent Crude Puts covering 449,950 barrels and $70 NYMEX Puts covering 275,000 barrels for the remaining of 2012. We continue to believe that our long-term outlook has never looked better.

With that overview, I’ll turn the call over to Tim Larkin, our CFO. Tim?

Timothy Larkin

Thanks, Norman. Before I discuss the company’s financial results released earlier today, I’d 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 continued to make progress during the fourth quarter and we’re excited about 2012. Our cash flow from operations continues to be solid and we’re on a strong liquidity position. As of December 31, 2011 we had $40.5 million available under our senior credit facility. After year-end we drew down an additional $10 million during February 2012.

Today we reported net income of $3 million for the quarter, or $0.04 per diluted share and adjusted net income of $6 million, excluding losses from hedging activities of $3 million. Additionally during the quarter, we generated $14.6 million of cash flow from operations, also our oil and gas production was 463,000 barrels of oil equivalent for the quarter or 5,000 barrels of oil equivalent per day.

Production from our two oil fields in California totaled 247,000 net barrels during the fourth quarter. A 3% increase from the 240,000 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 11% to 1.3 billion cubic feet during the fourth quarter compared to 1.17 billion cubic feet during 2010.

The average realized oil price for the fourth quarter of 2011 was $92 per barrel compared to $77 per barrel during the fourth quarter of 2010, an increase of 20%. Our average realized gas price for the fourth quarter was $3.47 per Mcf compared to $3.51 per Mcf in the fourth quarter of 2010.

Under our current oil purchase and sale contract with Conoco Phillips which expires in July 2012, the company sells its oil at a blended formula price of 87% of NYMEX for the first 1,800 barrels of oil per day and at the Midway Sunset price plus a $0.85 bonus and a premium for gravity adjustment for the balance of our production. We currently produce approximately 3,300 gross barrels of oil per day. Midway Sunset is currently selling at a premium of $10 to NYMEX.

During the fourth quarter we received a weighted average price, which approximated 98% of NYMEX light sweet crude. Also during the fourth quarter, we recorded a net loss from derivatives of $3 million, which included a realized loss from derivatives of $2.6 million and an unrealized loss from future derivatives of $400,000.

In order to protect the company against the decline in oil prices, but allowing for unlimited upside to oil prices, the company currently owns 499,995 Brent Puts with a strike price of $90 for calendar year 2012 or approximately 1,800 barrels of oil per day for the balance of 2012.

The company also currently owns 275,000 NYMEX Puts with a strike price of $70 per barrel for calendar year 2012 or approximately 1,000 barrels of oil per day for the remainder of 2012. As a result of improved oil prices, oil and gas revenues for the fourth quarter increased 21% to $27.3 million compared to 2010.

Total operating expenses increased 16% to $20.2 million during the fourth quarter of 2011 compared to 2010. Lease operating expense decreased 13% to $6.3 million due to lower plugging and abandonment costs. We expect oil LOEs to average approximately $20 per net barrel for the balance of 2012.

Depletion, depreciation and amortization expense for the fourth quarter increased 54% to $9.9 million compared to the fourth quarter of 2010. DD&A was $21.45 per BOE during the fourth quarter of 2011 compared to $14.86 per BOE during the fourth quarter of 2010.

This increase in DD&A on a per barrel basis resulted from higher estimated future development costs associated with the increase in our proved, undeveloped oil reserves as of December 31, 2011 compared to 2010 and a reduction in our gas proved reserves. Additionally, DD&A increase due to depreciation expense related to our new drilling rig.

General and administrative expense increased 6% to $4 million during the fourth quarter of 2011. This decrease resulted from an increase to our annual incentive compensation accrual recorded during the fourth quarter of 2011 compared to the same period in 2010. This increase was offset by a decrease in stock option expense during the quarter.

Interest expense increased 29% to $1.1 million during the current quarter due to an increase in the borrowings under the credit facility. Net cash flows provided by operating activities was $14.6 million during the fourth quarter of 2011 compared to $11.5 million during the fourth quarter of 2010.

For full-year 2011, we reported net income of $21.6 million for the full-year 2011 or $0.30 per diluted share, and adjusted net income of $24.3 million excluding losses from hedging activities of $2.7 million. Additionally, during the year we generated $47 million of cash flow from operations.

Our oil and gas production was 1.7 million barrels of oil equivalent for the year or 4,800 barrels of oil equivalent per day. The average realized price for oil in 2011 was $92 per barrel compared to $71 per barrel during 2010, an increase of 28%.

The average realized gas price for 2011 was $3.98 per Mcf compared to $4.09 per Mcf during 2010 a decrease of 3%. As a result of improved oil prices, 2011 oil and gas reserves increased 17% to $103 million compared to 2010.

Operating expenses increased 15% to $76 million during 2011 compared to 2010, the increase resulted from an increase in DD&A. DD&A was $17.46 per BOE during 2011 compared to $12.61 per BOE during 2010. Again, the reason for the increase in DD&A on a per barrel basis resulted from higher estimated future development costs associated with the increase in our proved oil, undeveloped reserves as of December 31, 2011 compared to 2010 and a reduction in our gas proved reserves. Additionally, DD&A increased due to depreciation expense related to our new rig.

Assuming the minimal level of activity in Wyoming, our forecasted 2012 capital expenditure budget is $71 million. $68 million related to our California oil fields and $3 million related to our Wyoming Natural gas fields.

This includes expenditures of approximately $48 million for drilling up to 20 producing wells and 9 injector wells in our WTU and NWU oil field in California. Additionally, this includes approximately $17 million for facilities and $3 million for a 3-D seismic shoot of our California properties.

During 2012, Warren entered into a new five-year $300 million senior credit facility with the Bank of Montreal, as the administrative agent, and five other participating banks. Our borrowing base was increased to $130 million. The next re-determination is next month in April.

As the 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 expenditure budget as commodity and financial markets change.

We reported first quarter and full-year 2012 production and capital expenditure 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?

Stephen Heiter

Thank you, Tim. Now, I’d like to update Warren’s operational details. In 2011, Warren drilled and completed 17 new wells at WTU consisting of 4 Upper Terminal wells, 3 Ranger wells, 9 Tar wells and 1 well that penetrated both the Ford and the 237 formations.

Thirty day initial production rates for the new Tar wells averaged just over 175 barrels of oil per day. These new Tar wells typically experience a 50% to 60% reduction in producing rates after a few months, which is a normal hyperbolic decline and results in our typical ultimate recoveries of 100,000 to 150,000 barrels of oil per well.

Project economics for the 9 Tar wells indicated rates of return of over 100% with the 12 to 14 month payout at $80 Midway Sunset pricing and a 10% rate of return at about $40 Midway Sunset pricing. The 4 new Upper Terminal wells averaged about 84 barrels of oil per day initially and have experienced normal declines to date.

Note that our two best Upper Terminal wells averaged over 200 barrels of oil per day initially with expected ultimate recoveries of about 175,000 to 200,000 barrels of oil. The 3 new Ranger wells averaged about 70 barrels of oil per day and are also experiencing normal decline rates. Over the long run, we expect these wells to range from 75 to 150 barrels of oil per day initial rates with ultimate recoveries of 125,000 to 200,000 barrels of oil.

Project economics indicate that 50% to 100% rate of return for these wells at $80 Midway Sunset pricing and a 10% rate of return at $40 to $50 pricing. Three of the new 2011 wells were drilled to test potential Tar D1A reserves in a new fault block. The thirty day initial production rate for each of these three new wells averaged over 160 barrels of oil per day confirming new reserves. Additional wells are being planned in this fault block for 2012 including an injection well for pressure support.

The Ford formation well was drilled through the deeper 237 formation in order to obtain modern log data through the deeper zones including a seismic log to tie to the upcoming 3-D seismic shoot. A well was completed at both the 237 and the Ford zones and had a thirty day initial production rate of 50 barrels of oil per day.

Based on the results of this well, we’re planning a multi-year water flood development program likely with 50 to 60 producers and 20 to 30 injectors. Two producers and three injectors are planned this year pending DOGGR approval of our water flood plant which we intend to complete during the second quarter of this year.

Warren’s new drilling rig performed trouble-free during the third and fourth quarters. As previously mentioned, we had experienced significant startup problems with some of the major rig components. All those components have been repaired or replaced, and a comprehensive maintenance program has been developed and is being implemented. Furthermore, a significant total oil cost improvements have been made with more to be implemented throughout 2012.

We contracted for a second drilling rig at WTU in September to allow us to accomplish our proposed 2011 drilling program. The rig drilled and completed five wells and was released in December.

As previously reported, in June of 2011, we received approval from the DOGGR to commence water injection into our Tar injection well drilled in 2010. Current injection rate is about 8,000 barrels of water per day.

We also recently received approval for a second Tar injector and completed the new well a couple of weeks ago. We’re currently injecting into this well at a rate of 12,000 barrels of water per day.

In addition, an application has been submitted for Tar injector in our new east of Banning fault block, and we’re anticipating approval in the second quarter of 2012. Over time, this injection will increase the Tar reservoir pressure and shallow the production decline.

On July 19, 2011, the AQMD certified the company’s CEQA documents and issued all of their related permits including gas handling equipment. These permits allowed us to install several pieces of best available controlled technology equipment including a clean enclosed burner, a new heater/treater and gas injection compressor. A clean enclosed burner and heater/treater are currently in operation, and construction of the gas injection compressor is nearing completion.

Upgrades to the production and water handling facilities in the company’s north Wilmington Unit are almost complete. This work will accommodate anticipated increased oil production from NWU when drilling activity is resumed later in the year. The drilling schedule is contingent upon timely approval by the DOGGR of our proposed water injection wells. In addition, we’re in the process of acquiring a necessary Townlot around our NWU central facility for a second drill site for the nearly 50 wells in our development plan.

Warren issued our full reserves press release on January 26, 2012. To summarize, California oil reserves increased 46%, compared to 12/31/2010 with a PV-10 of $499 million, reflecting the results achieved during our 2011 drilling program. The five-year old Tar Horizontal Development Program continued fairly smoothly with the drilling of nine very good wells as mentioned earlier. Seven of the nine first ever Ranger and Upper Terminal horizontal sinusoidal wells were drilled in 2011, advancing these two reservoirs from the concept oil stage to full-field development.

Importantly, we added a new reservoir for full-scale development, the Ford, and we laid the groundwork for a 3-D seismic shoot scheduled to begin next month, which will begin to provide significant geologic insight for our Ford shallower reservoirs by year-end 2012 and reveal additional deep potential in the 237/Schist and other possible reservoirs.

Overall, we believe we’ve more than 200 high rate of return producing wells to drill in our Ford shallower reservoirs along with over 100 injectors for water flood support. The 23 well WTU and sixth well NWU 2012 drilling program will further advance our reserves growth by year-end 2012.

The gas reserves for our Wyoming properties declined 36% during 2011, with a $27 million PV-10 reflecting much lower gas pricing and some negative adjustments to the production type curve.

Commencing in July 2011, Warren participated in the drilling of one well in the Catalina Unit and also 25 new coalbed methane wells in the Spyglass Hill Unit in the Atlantic Rim area of Wyoming.

Our 25 Spyglass Hill Unit CBM wells have been drilled, placed on production and are now in the de-watering stage. The unit should be validated by production later this week.

We continue to evaluate the potential of Warren’s Atlantic Rim acreage for Niobrara oil development. We recently concluded a regional geologic study of the Niobrara and are considering the best options for development.

Thank you, and now I’ll return the call to Norman.

Norman Swanton

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

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) And your first question will come from the line of Leo Mariani with RBC. You may proceed.

Leo Mariani – RBC Capital Markets

Hey, good morning here guys.

Norman Swanton

Good morning, Leo.

Leo Mariani – RBC Capital Markets

I wanted to see if you guys could provide a little bit more color on some thoughts around potential acquisition, I think Norman, you had mentioned, looking at some oily areas, have you guys narrow that down at all to some potential spots you may look to buy?

Norman Swanton

I’d say that we informed an internal group to review and to seek out opportunities for us. They’re not tied up in day-to-day operations. So we’ve taken assess, we’re looking at quite a few things, and so I think the news is that we’re focusing on this area, but we’ll report as we go on, nothing to report yet.

Leo Mariani – RBC Capital Markets

Okay. And what did you guys learn from the regional geologic study you just – you’ve finished up in the Niobrara?

Stephen Heiter

This is Steve. Mostly, structural issues, we had at geological firm study that for us and they’ve identified areas within our leases where we might experience the best faulting traps and fracture areas and so that was the main thing we learned from it. Leo, it is, we’re in the best locations might be within our leases.

Leo Mariani – RBC Capital Markets

Okay. And I don’t know you guys -- if you guys saw it, but I guess Double Eagle talked about a well they reported recently, just wanted to get a sense of where if it is relative to your property, and any thoughts you may have around that?

Stephen Heiter

It’s pretty close there. We’ve acreage around it. So it’s very close to where our leases exist, and what they report is I think was pretty similar to what they reported recently for wells drilled through the Niobrara around that location. So, it contains oil. We know that. And there are potentially some reservoirs below the Niobrara, and so we’ll just have to wait and see what they report when they finally give us the frac in our production. I think they’ve their ways to go yet before they’re actually going to have in our production.

Leo Mariani – RBC Capital Markets

All right. And I think you folks also mentioned that your oil contract on California rolling off in July, any progress making on renegotiating needs at this point, and I guess that there are more than one potential buyers for the oil down there?

Norman Swanton

There are potential buyers. Although, one has to be aware, we ship by pipelines. So you’ve to get it into the right pipeline and connection. But those discussions are ongoing at the present time. So I think that what we’re seeking to do is to renegotiate another contract probably for the same duration or so three years, and at Midway Sunset pricing rather than WTI?

Leo Mariani - RBC Capital Markets

Got you. So index to Midway Sunset basically?

Norman Swanton

Yes.

Leo Mariani - RBC Capital Markets

Okay. And you guys talked about layering some new Puts on recently here. I want to get a sense of what the cost was for those new Puts?

Norman Swanton

The 90 Puts were purchased at $1.80 per barrel. The 70 Puts really left over from a former collar, and I’d say the cost basis was about $1 a barrel on those Puts.

Leo Mariani – RBC Capital Markets

Okay. And I guess you guys are talking about in your guidance that your oil volumes are going to be kind of flat in the first quarter of ’12 versus the fourth quarter of ’11, I know you drilled a lot of wells in the fourth quarter I guess, a little surprising to see those flat, is there any color you have around that?

Stephen Heiter

Yeah, this is Steve. We had about I think, 9 or 10 well failures in the last quarter of ’11 that were just typical ESP failures. We’ve had extremely long runs out of those wells up to five and six years, but we only expected three. And the failures that we had were typical electrical failures, but unfortunately the wells that failed were, some of them are in the middle of [cellar 3] for example, where we have a large project going on, of putting in permanent hard-line production of gas lines through our facilities, they were temporary lines and so we could not access those wells, and also some of the wells were around where the drilling rig was and drilling rig is now moved and we’re starting to put some of those wells back on production. Plus we lost five wells as a result of a – some mud contamination from the drilling rig and, so we’ve got some – a number of wells down that we’ll be putting on. We got two service rigs working on them, and we’ll be putting those on over the next couple of months.

Leo Mariani – RBC Capital Markets

All right. Thanks, guys.

Norman Swanton

Yeah.

Operator

Your next question will come from the line of Phillip Jungwirth with BMO Capital Markets. You may proceed.

Phillip Jungwirth - BMO Capital Markets

Hi. Good morning, guys.

Norman Swanton

Good morning.

Timothy Larkin

Good morning.

Phillip Jungwirth - BMO Capital Markets

On the gas production guidance, does that assume that you’ll be drilling in Wyoming this year?

Norman Swanton

Wyoming?

Phillip Jungwirth - BMO Capital Markets

Yeah.

Norman Swanton

We believe that Anadarko doesn’t have any plans to spend any money on drilling this year, and if they don’t then, we don’t have any plans as well. So, no – the answer is, no.

Phillip Jungwirth - BMO Capital Markets

Okay. And then, how does – deciding not to drill impact the 25 well per year commitment that you’ve talked about in the past?

Timothy Larkin

Well, if we don’t drill this year then the leases in the units around the participating or producing areas start to contract, would have a two year extension for all the leases that are now outside the unit, and they would have to be drilled on in the next couple of years. So the shorter answer is; the unit contracts around the wells that are currently producing. And those – that contraction will result in a number of leases outside the new area and those leases will begin to expire later this year and will result in two-year extension. It’s kind of convoluted, but I hope that answered your question.

Phillip Jungwirth - BMO Capital Markets

Yeah. That’s clear enough. Is there any chance of having to shut in production due to low gas prices in Wyoming?

Norman Swanton

Well, we looked at that and its cash flowing, but it’s not attractive for new investment frankly. And so, we just have to see as we go, if we did – if gas prices went lower, went down to $1 an Mcf, I think we’ll probably shut it in and wait it out or. We’re also looking at, what alternatives we may have with respect to the Atlantic Rim, we've reported out several times and we continue to pursue possibilities for that asset.

Phillip Jungwirth - BMO Capital Markets

Okay. And then, some more question moving to California. Does the oil production guidance, I assume that implies that you’ve drilled the wells in NWU this year. Is that correct?

Stephen Heiter

Yeah, we've three producing wells, and three injection wells planned for the fourth quarter. And if the DOG gives us approval for water injection, we could accelerate that because the facilities will be ready probably within a couple of months. But we’re giving ourselves some time for the Division of Oil and Gas to review our proposals for water injection and get going. We’ll have to contract a rig and we’re not sure of the availability. So there’s lot of work to do before we do that, and that’s why we timed it in the fourth quarter.

Phillip Jungwirth - BMO Capital Markets

Okay. And then can you talk about the differences in well costs between the Tar, the Ranger, the Ford and the Upper Terminal?

Stephen Heiter

Yeah, we’re in the middle right now of a redesign of some of our wells. We’ve reported a couple of times, that last year we did not have a good year on a drilling standpoint both with the rig and we had a lot of pretty severe down-hole problems and those have been resolved and the wells we’ve drilled in the last few months have gone very smoothly, and – but we’re going to be redesigning and continuing to improve our drilling performance.

What we’re using for AFE cost, I’ll give you a range here, maybe $1.6 million for Tar wells, $1.7 for Ranger and UT, $1.2 for the Ford. But we expect to get those costs – further AFE costs in December of ’11, and we expect to reduce those costs anywhere from 10% to 25% depending on the reservoir throughout the course of the year.

Phillip Jungwirth - BMO Capital Markets

Okay, great. And then LOE declined quite a bit in the fourth quarter, do you have an expectation going forward, how we should think about the LOE cost?

Stephen Heiter

Yeah. If you exclude property taxes, they went up significantly which is a good thing, because if the reserves are resolved, other than that the cost that fluctuates the most is our plugging and abandonment, we don’t consider that LOE, but from a financial standpoint I know its consider the LOE operating cost. And we’re accelerating our abandonment activities beyond what's required by the Zoning Administrator, because we want to get rid of all the wells out in the neighborhood. We've quite a few years, we’re allowed to do that, but we’re trying to accelerate it.

So we’re spending more than what we need to on P&A’s, but strictly at the least operating levels from the superintendent bound, we've actually reduced expenses over the last couple of years. And what will impact this year is that we expect more pump failures, because like I’ve mentioned, we’ve had five and six year runs out of some of these pumps and one of these years a lot of them are going to fail and so, we would expect maybe those cost to go up a little bit, barely about a $100,000 per well and I think I’ve planned 15 of those for the year, around 15.

And the other thing that might affect our operating expenses this year is purchasing water for injection. In the last couple of years, we've had the opposite problem, we had too much water and couldn’t get rid of it and had to shut wells then. And now with our Tar injection going up significantly, which is good to increase the pressure, we’re out of water. We potentially will be out of water throughout the year if we get our injection permits. There won’t be buying water, and right now the cost is about $0.27 a barrel for fresh water and we’ve plans to tie in just some grey water, which will reduce that cost that we’re waiting on the suppliers on that. So the two things that impact our field expenses this year will be pump changes and potentially purchasing water.

Phillip Jungwirth - BMO Capital Markets

Okay, great. Thanks guys.

Stephen Heiter

You’re welcome.

Norman Swanton

Thank you.

Operator

Your next question comes from the line of J.B. Lowe with Sidoti. Please proceed.

John Lowe - Sidoti & Company

Good morning, guys. I just had a quick question, what do you estimate – how many permits do you estimate you’ll need above and beyond what you already have to complete your 2012 drilling program?

Stephen Heiter

We’ve nine in the plans, and we’ve one that we’ve received and drilled a well on injection at Tar well. So eight more, a couple in each reservoir and three at NWU. So that adds up to nine.

John Lowe - Sidoti & Company

Okay. And then, is there any reason why the Ford wells are not going to be sinusoidal and just doing vertical?

Stephen Heiter

Yeah, there is a reason. Let me have Ron Morin, our – who is responsible for our development plan to answer that question. Ron?

Ronald Morin

Yeah guys, its Ron. Yeah, Ford is about 1,200 feet thick; it’s about 20 sands, 20 to 40 foot thick spread across 1,200 feet. So it just would be impractical to try do a sinusoidal. The other reason is – we actually did a water flood 30 years ago to the South, it has also very good response with the five spot, more or less the five spot type patterns. So it looks like those sands are pretty laterally continuous and we should end up with very good response with some kind of vertical pattern designs.

John Lowe - Sidoti & Company

Okay, great. And then lastly on purchasing freshwater to inject, is there any sort of environmental issues that could crop up from – I know that California is probably a short water, so is there anything that will be a problem with that?

Stephen Heiter

Well, we’ve asked that question, and we don’t believe so. We’ve purchased water before. We did this a couple of years ago for – not very long, for a few months and there was no issue then, and we don’t believe there will be an issue now, no…

John Lowe - Sidoti & Company

And then…

Stephen Heiter

…anyway, we’re still trying to continue looking into tying in the grey water, and I think that could happen as early as next year.

John Lowe - Sidoti & Company

Okay, good. That was my next question. All right, that’s it from me, thanks.

Stephen Heiter

Welcome, Lowe.

Operator

Your next question comes from the line of Ray Deacon with Brean Murray. Please proceed.

Raymond Deacon - Brean Murray, Carret & Co

Yeah. Hey, I had a question about the 200 drilling locations and if you could provide some breakout if that by Tar versus Ranger or Ranger or Upper Terminal?

Stephen Heiter

Yeah. Again I’m going to defer to Ron on that question.

Ronald Morin

Yeah, I’ll give you some ballparks. So we’re actually little bit above 200, but in round numbers it’s probably 60 to 70 in the Upper Terminal, that’s the J and the HX horizon within the Upper Terminal, we actually have another layer below that we haven’t really fully delineated to put in our development inventories called the [K&Y] sands. We’ve got about 30 to 40 in the Ranger at WTU, about 24 producers, 20 to 24 at NWU. In the Tar, evolved horizons we probably have in the neighborhood of 25 to 30…

Raymond Deacon - Brean Murray, Carret & Co

Okay.

Ronald Morin

…locations left there. And then in the Ford, it’s probably 50 to 60 as we kind of mentioned, and all of those numbers are just the producers.

Raymond Deacon - Brean Murray, Carret & Co

Okay.

Ronald Morin

So that should give you something a little bit about 200.

Raymond Deacon - Brean Murray, Carret & Co

Okay, great. And I was wondering with the guidance for ’12, what’s assumed in terms of additional water permits, how many do you need to receive to get that – those kind of numbers?

Stephen Heiter

Well, we’ve nine in our plan. We’ve received one, and we also have six UT wells that we had applied and received permission to convert from producers to injectors. That’s part of our plan. So, nine new wells and six conversions and the sixth conversion and one well have been approved and we’re anticipating approval on the rest of them. It’s a very good chance we’ll get as many as we need this year, but there is still a lot of work to do with the DOG. Some of them are not going to be slam dunks as there are lot of education and lot of work to do with the DOG, but we’ve a number of people working on that almost everyday.

Raymond Deacon - Brean Murray, Carret & Co

Got it, got it. And I’m really just curious, any comments in terms of – you mentioned your interest in pursuing acquisitions, it looks like you’re drilling well within cash flow and you’ve got the new boring base, so I guess are you targeting oil or gas or and would it be California or somewhere else?

Norman Swanton

Well, I think our first preference would be California oil.

Raymond Deacon - Brean Murray, Carret & Co

Okay.

Norman Swanton

We are here, that our people are here, our technology is here, and California has a lot of areas as you know from the LA basin on up. So that is a potential area, although there are other basins, as you know, West Texas and Rockies, but I think we’ve – we’re going to be focusing pretty close to home, initially.

Raymond Deacon - Brean Murray, Carret & Co

Great. Okay, got it. Thank you.

Operator

(Operator Instructions) Your next question comes from the line of Jack Aydin with Keybanc Capital Markets. You may proceed.

Jack Aydin - Keybanc Capital Markets

Hey, guys.

Norman Swanton

Hey, Jack.

Jack Aydin - Keybanc Capital Markets

This is for Tim. DD&A going forward, should we use similar DD&A that you had in the first quarter for 2012 and another one is the G&A, should we use the same for modeling purposes?

Timothy Larkin

Yes. For 2012, we’re looking at $21.45 per BOE and similar numbers on G&A too, Jack, yeah.

Jack Aydin - Keybanc Capital Markets

The other question, I’m just puzzled with the comment Norman making about the acquisition, you got inventory in California and you’re limited in cash flow and spending, and doing an acquisition what would you bring to the table in terms of doing an acquisition outside of your area, and if why?

Norman Swanton

Well, I think that our sinusoidal drilling concepts are excellent candidates for other water floods. I mean, we started this whole process by acquiring units in the Wilmington field that’s been in production since 1937, and it was abandoned by Exxon and the majors, and look what we’ve done to – to-date, and what our potential is. I think that there are a lot of whether they’re water floor or pre-water flood, you know very well the major formations that we were thinking initially maybe we’d have to go with ASP tertiary, but there what we’re drilling with these horizontal wells and sinusoidal wells, we’re getting oil that’s not going to reach before to a large extent as well as the water flood oil.

So I think that we’ve in our minds validated cost-wise and productivity-wise and payout-wise why wouldn’t we duplicate that in other fields. So we’re now looking, I think that the financing is available, and the – these typically would not be necessarily new fields, these would be old fields with low production, but large unrecovered reserves.

Jack Aydin - Keybanc Capital Markets

Thank you.

Norman Swanton

Thank you.

Timothy Larkin

Thanks, Jack.

Operator

Your next question is a follow-up from Phillip Jungwirth with BMO Capital Markets. Please proceed.

Phillip Jungwirth - BMO Capital Markets

Hey guys. Just wanted to follow-up on the locations question, do you have the breakout that you gave? Do you have a number for how many of those were booked as PUDs at year-end?

Ronald Morin

Yeah, this is Ron. Yeah it’s about 60 of those were PUDs on the existing reserve ledger.

Phillip Jungwirth - BMO Capital Markets

Okay. And then can you provide how many of those were Tar versus Upper Terminal versus Ranger?

Ronald Morin

Of the PUDs?

Phillip Jungwirth - BMO Capital Markets

Yes.

Ronald Morin

I believe 14, either 12 or 14 of Tar.

Phillip Jungwirth - BMO Capital Markets

Okay. And then the remainder are probably evenly split between Ranger and Upper Terminal?

Ronald Morin

Yeah. They are pretty much, yeah.

Phillip Jungwirth - BMO Capital Markets

Okay. And then that the comment about the Upper Terminal and the Ranger wells achieving payout in one to two years, what are those wells need to recover over that time period to achieve that payout?

Ronald Morin

Well, the decline curves for the ones we drilled so far we probably don’t have enough to make a type curve yet, but they’re in the 125 to 175 range on decline. Of course the payout would be – they’re 25 year, 27 year life on those wells, but the payout would be in the first ...

Norman Swanton

How many barrels – be produced to achieve payout.

Ronald Morin

How many barrels to achieve payout? Lets see, wells are 1.6 million divided by our average margin, well that will give you probably somewhere in the neighborhood of 30,000 maybe.

Phillip Jungwirth - BMO Capital Markets

Okay, yeah …

Ronald Morin

That makes sense?

Phillip Jungwirth - BMO Capital Markets

Yeah. That’s what I had, I can do that math also.

Ronald Morin

Yeah, I will guess it’s about 30.

Phillip Jungwirth - BMO Capital Markets

Okay. Thanks, guys.

Norman Swanton

Okay.

Operator

And at this time there are no further questions. I’d like to turn the call to Mr. Norman Swanton for closing remarks.

Norman Swanton

Thank you, operator. Thank you for your interest in Warren Resources and good day.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a wonderful day.

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