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Warren Resources, Inc. (NASDAQ:WRES)

Q1 2012 Earnings Call

May 1, 2012; 10:00 am ET

Executives

Norman Swanton - Chairman, President & Chief Executive Officer

Steve Heiter - Executive Vice President; Chief Executive Officer of Warren E&P, Inc

Ron Morin - Senior Vice President of Development; Executive Vice President of Warren E&P Inc.

Tim Larkin - Executive Vice President & Chief Financial Officer

Analysts

Ray Deacon - Brean Murray

Phil McPherson - Global Hunter Securities

Jack Aydin - Keybanc Capital Markets

Brad Heffern - RBC Capital Markets

Operator

Good day ladies and gentlemen and welcome to the first quarter 2012, Warren Resources earnings call. My name is Caressa and I will be your operator for today. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions)

I will now turn the conference over to your host for today call, Mr. Norman Swanton, Chairman, CEO of Warren Resources. Please proceed.

Norman Swanton

Thank you. Good morning everyone. Thank you for joining us for Warren Resources first quarter 2012 financial and operating results conference call.

We are conducting the conference call this morning from our Long Beach Office in California. With me is Steve Heiter, our CEO of our Principal Subsidiary, Warren E&P; Ron Morin, our Senior Vice President responsible for our development; and Tim Larkin, our Executive Vice President and CFO 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 would like to briefly comment on our performance for the first quarter of 2012 and the future direction of the company as follows.

We continue to be in a strong financial position, thanks to our virtually 100% oil drilling success in Californian, with target returns of 50% to 100%. As a result of the 2011 and first quarter 2012 drilling program, Warren exited the first quarter at a rate of 3,698 gross barrels of oil per day at our two Wilmington field units, compared to 3,392 barrels for the fourth quarter of 2011. With an inventory of over 200 new producing wells targeted in the Wilmington field, we expect to see continuing oil production and oil reserve improvements throughout 2012 and beyond.

Recent production gains resulted from new horizontal wells in the Tar, Ranger and Upper Terminal oil reservoirs and later it’s oil production from our units in the Wilmington field in Californian. Our oil production increased 19% to 249,000 barrels of oil in the first quarter of 2012 compared to 210,000 barrels of oil produced in the first quarter of 2011.

Our cash flow from operating activates increased to $12.9 million in the first quarter of 2012 compared to $7.7 million in the first quarter of 2011. 2012 cash flow from our operations is expected to cover 2012 capital expenditures.

Although we had water injection permitting challenges in 2011, during the first quarter of 2012 we received seven new water injection permits in California. To protect 2012 cash flows, we have in place $90 Brent Crude oil puts, covering approximately 500,000 barrels of oil and $70 NYMEX Puts covering another 275,000 barrels for the remainder of 2012. And finally I continue to believe believe that our long-term outlook has never been brighter.

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

Tim Larkin

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 are excited about 2012 and certain challenging issues of the past seem to be behind us. Our cash flow from operations continues to be solid and we are in a strong liquidity position. As of March 31, 2012 we had $30.5 million available under our senior credit facility.

Today we reported net income of $3.8 million for the quarter or $0.05 per diluted share and adjusted net income of $4.7 million, excluding losses from hedging activities of $900,000. Additionally, during the quarter we generated $12.9 million of cash flow from operation. Also our oil and gas production was 454,000 barrels of oil equivalent for the quarter or approximately 5,000 barrels of oil equivalent per day.

Production from our two oil fields in California totaled 249,000 net barrels during the first quarter, a 19% increase from the 210,000 net barrels produced during the same period in 2011. Additionally, natural gas production, primarily from our Atlantic Rim Project in Wyoming was strong and overall natural gas production increased 5% to 1.23 billion cubic feet during the first quarter compared to 1.18 billion cubic feet during 2011.

The average realized oil price for the first quarter 2012 was $100 per barrel, compared to $87 per barrel during the first quarter of 2011, an increase of 14%. On average, realized gas price for the first quarter was $2.85 per Mcf, compared to $4.15 per Mcf in the first quarter of 2011.

Under our current oil purchase 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 Midway Sunset price plus an $0.85 bonus and a premium for gravity adjustment for the balance of our production. We exited the first quarter producing over 3,600 gross barrels of oil per day. Midway Sunset is currently selling at a premium of $9 to NYMEX.

During the first quarter we received a weighted average price, which approximated 97% of NYMEX light sweet crude. Also during the fourth quarter, we recorded a net loss from derivatives of $900,000, which included a realized loss from derivatives of $400,000 and an unrealized loss from future derivatives of $500,000.

In order to protect the company against a 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 increased oil production and improved oil prices, oil and gas revenues for the first quarter increased 22% to $28.4 million compared to 2011.

Total operating expenses increased 31% to $22.9 million during the first quarter of 2012 compared to 2011. Lease operating expense increased 10% to $8.5 million due to increased oil and gas production. We expect oil LOEs to average approximately $20 per net barrel for the balance of 2012.

Depletion, depreciation and amortization expense for the first quarter increased 65% to $10.1 million compared to the first quarter of 2011. DD&A was $22.25 per BOE during the first quarter of 2012 compared to $15.11 per BOE during the first quarter of 2011.

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

General and administrative expense increased 20% to $4.3 million during the first quarter of 2012. This increase resulted from an increase to employee compensation expense. Interest expense increased 36% at $800,000 during the current quarter, due to an increase in the borrowings under our credit facility.

Net cash provided by operating activities was $12.9 million during the first quarter of 2012, compared to $7.7 million during the first quarter of 2011. Assuming a 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 nine injector wells in our WTU and MWU oil fields in California. Additionally, this includes approximately $17 million for our facilities and $3 million for a 3-D seismic shoot of our California properties.

During December 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 scheduled for this month.

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 guidance in our press release disseminated this morning.

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

Stephen Heiter

Thanks Tim. In the first quarter of 2012, Warren drilled and completed six new wells at WTU, consisting of two ranger wells, three Tar fiduciaries and one Tar injection well. 30-day initial production rates for the new Tar wells averaged just over 135 barrels of oil per day. Project economics indicate greater than 100% rate of return for these wells at $80 Midway Sunset pricing.

The new Tar injection well is taking about 8,000 barrels of oil per day at 800-PSI injection pressure. The two new ranger wells averaged about 55 barrels of oil per day. Project economics for these two wells indicate a 30% to 35% rate of return at $80 Midway Sunset pricing and 40% to 45% at $100 pricing.

Warren’s new drilling rig continued to perform trouble free during the first quarter. Furthermore significant total well cost improvements have been made with more to be implemented throughout 2012. The average drilling and completion time per well in the first quarter of 2012 was 13 days compared to 17 days in the 2011 drilling program for a 20% reduction in time.

Based on the results of the Ford well drilled in 2011, we continue to plan 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 this quarter.

Agreements have been received for approximately 90% of the shoot area for our upcoming 3-D seismic shoot, which is now scheduled for 45 days during July and August of 2012. Upgrades to the production and water handling facilities in the company’s North Wilmington Unit are nearing completion. 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 are in the process of acquiring the necessary Townlots around our NWU central facility for a second drill site for the nearly 50 wells in our development plants.

These operating expenses at the field level for our California operations were $13.45 per barrel of oil net, compared to $14.87 for the first quarter last year. We expect fairly flat fuel expenses throughout 2012 depending primarily on the number of down hole pump failure experienced at both units.

In Wyoming all 25 Spyglass Hill Unit coalbed methane wells that were drilled in 2011 have been placed on production and the unit has been validated. 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 for participating today and now I’ll return the call to Norman.

Norman Swanton

Thank you Steve. Operator, we will now take questions.

Question-and-Answer Session

Operator

(Operator Instructions) And your first question comes from the line of Ray Deacon of Brean Murray. Please proceed.

Ray Deacon - Brean Murray

Yes, hi Steve. I was wondering if I could ask you a question about reserved bookings and what kind of impact not having the water injections had and whether you would see a improvement, would you expect with the water permits you’ve gotten this year.

Steve Heiter

Yes, I’m going to let Ron answer that question, okay.

Ray Deacon - Brean Murray

Yes, thanks.

Ron Morin

Yes Ray, I would say most of the permits that we really needed we’ve gotten. So I don’t know that that’s really had a significant impact on our reserve bookings at this point. We are just staying a half a step ahead of what we need at this point, if that makes sense to you.

Ray Deacon - Brean Murray

Okay, got it. Now, I was thinking that last year you might have had some negative revisions because of the pressure declines for not having it, but anyway. I guess just one other, so in terms of the borrowing base you talked about that you are in a process of a re-determination. I guess what are your expectations there and where do you see that liquidity number at the end of the year.

Tim Larkin

Well Ray, this is Tim. It’s kind of hard to say. We have our meeting next week with our bank group. Obviously the strength of oil pricing and the strength of our continued success in California will have a positive effect on the oil side and with negative gas pricing these days and the bank debts coming down, there is probably going to be – my guess would be it would be a positive result on oil and negative on gas, primarily due to percentage.

Ray Deacon - Brean Murray

Okay, got it.

Norman Swanton

Ray, this is Norm Swanton. Just wanted to comment on your question on reserves from this perspective. As you know we increased our oil reserves 46% at year-end 2011. However on the natural gas side we lost 24 bcf for a million barrels, mostly through the steep decline in gas prices. It wasn’t the constraint of water injection wells per say, other than the timing of the drilling and converting the puts to PDPs, so I just wanted to clarify that.

Ray Deacon - Brean Murray

Got it. I guess I think on a prior call you had mentioned that you felt that by Arial possibly you’d be back to kind of normal course issuance on water permits with the DOGGR and I was wondering whether you felt like that was the case or because it’s a little slow.

Steve Heiter

As we mentioned in the call, this is Steve, we’ve gotten seven this year. One of those was the Tar injection well which is taking as much water as we needed to take. We are currently injecting all the water that we have and the other six were convergence to injectors from producers, which we will do throughout the course of the year, depending on our water management plant or water flood management.

We have an engineer that’s specifically tasked with water flood management and we’ll do those throughout the course of the year. We may not do all six, but we’ll do as many as we need and we have applications in for a couple of Ranger wells and other Tar injection wells and the Ford wells we mentioned and we expect to get those throughout the year.

DOGGR still has resource issues and we are in line and we don’t really expect it. Hopefully we don’t expect it to impact our drilling program. A couple of things may have to side a little bit, but I don’t think it’s going to be significant.

Ray Deacon - Brean Murray

Got it and when do you expect to hear on the NWU permits?

Steve Heiter

Ron, do you have a feel for that.

Ron Morin

Yes, we are currently working on that. Actually there’s some fairly good news on that, that because there is existing injectors that cover the majority of the lease, we think that may be just a simple process, and not an AOR process. It may be a two week approval process similar to what we got in the some of the Upper Thermal injectors because we have injection wells near by, so we are working with them now, but we think that that’s probably likely.

Ray Deacon - Brean Murray

Great, thank you.

Ron Morin

Your welcome.

Operator

And your next question comes from the line of Phil McPherson of Global Hunter Securities. Please proceed.

Phil McPherson - Global Hunter Securities

Hey, good morning guys.

Steve Heiter

Good morning.

Ron Morin

Good morning Phil.

Phil McPherson - Global Hunter Securities

Hey Steve, you started breaking down the permit thing. I wanted to ask kind of a bigger question. When you think of the fields over the next kind of two to three years, how may permits do you think you need to get and what’s kind of the timeline on filing them and staying kind of ahead of the course.

Steve Heiter

I may ask for a little help from Ron on this, but the Ford development plan, our water flood management plan for that, we are getting some help from our Niobrara tool and that plant should be ready this quarter and that should cover most if not all the Ford development over the next three or four years. So we will find out about that one fairly quickly and Ron just explained the NW, which covers almost all the field. So that shouldn’t be much of a problem.

We might continue to have some problems with a few wells at WTU, but right now we are in a pretty good shape with what we have and what we expect to get later this year and probably for the next year or two in our development plan.

Ron, do you have anything to add to that?

Ron Morin

Yes Phil, what I’d add to that is we continue to work with the DOGGR, we continue to I think come up with innovative solutions so they can lead their way to approving these permits and that seems to be working very well. We proposed some unique things that I think it really helped them focus on what the risks are and pay attention to what good engineering judgment will dictate. That seems to be working well.

So I would say back to your original questions, over the next two to three years, I don’t anticipate any significant issues with getting permits. Like I said earlier to Ray, we tend to stay a half a step ahead of them. Like Steve said, they do have resource issues, so there are bottlenecks for sure, but I think we’ve gone from things taken a year or two to things taken one or two or three months.

Phil McPherson - Global Hunter Securities

That’s great news. Can you also break down for me, you talked about $17 million in facility upgrades and I was wondering if you could break it down as far as what you’re actually doing between the two fields and also it seems like we do a lot of upgrade every year. Are we near the end or is just a kind of a number to think of going forward annually.

Steve Heiter

No, we are pretty close to the end on our upgrades. A lot of that $17 million, I’ll break down the biggest one for you. We’ve got $3 million or $4 million of seismic and we have $3 million or $4 million for gas shales, which we plan to have probably implemented towards the end of 2013, that’s a long process, its about a two year process, we are right in the middle of it and so that’s a large part.

There is almost half a plan right there and the upgrades are to the NWU facilities in advance of our development program. Those we finish in a few months and also the Satellite 7 at North Wilmington Unit, we are completing putting in a drilling seller there, which was quite expensive, we are in the last states of that. And at WTU we are in really good shape.

We are finishing up on some seller three work, which puts all those wells connected to our process facilities with hard-lines and urban electric power and so towards the end of this year, we are going to be in pretty good shape and our facilities budge in two or three years should be nowhere near what we have been spending in the last two years.

Phil McPherson - Global Hunter Securities

And Steve, on that drilling seller, that’s the 50 wells for the second type that you referenced before.

Steve Heiter

No, that’s the first sight, that’s the one that we will be drilling on hopefully later this year. Now the second one, we are still acquiring the Townlot, so that would have to be build out sometime in the next couple of years and it would be a similar capital cost to what we are doing now at Satellite 7. But that will be probably at the earliest, late 2013 or may be 2014.

Phil McPherson - Global Hunter Securities

And to build a site, is that like a $3 million to $5 million or something?

Steve Heiter

No, it’s less than that. It’s probably under $2 million.

Phil McPherson - Global Hunter Securities

Okay great.

Norman Swanton

And Phil, if I can add to that, I think last year was a really important kind of proof of concept here for the Upper Terminal, the Ranger and even the Ford and I think we advanced that significantly and I think the infrastructure that Steve is talking about is parallel to that. We are really in good shape on both fronts, both advancing the WellComps, the concepts and getting the infrastructure. I would say Steve, we are 80%, 90% of the way there by the end of the year.

Steve Heiter

Yes.

Phil McPherson - Global Hunter Securities

Yes, it sounds like you made a tremendous amount of process. So congratulations on that.

Steve Heiter

Yes, thanks Phil.

Phil McPherson - Global Hunter Securities

And I was going to ask on the rig, you had a one electric operated rig that you owned and I think you released the one. Are these permits – well, do you bring a second rig in the back half of the year. Can you complete this program with just the one rig?

Steve Heiter

The WTU program will be completed with the rig that we own, the one rig. The NWU program, which is a couple of miles away would require a second rig.

Phil McPherson - Global Hunter Securities

Okay, great, that’s all I’ve got guys. I appreciate it.

Steve Heiter

Okay thanks.

Ron Morin

Thanks Phil.

Operator

And your next question comes from the line of John Abbott. Please proceed.

John Abbott - Pritchard Capital Partners

Good morning.

Steve Heiter

Good morning John.

John Abbott - Pritchard Capital Partners

I just have one quick question; it may have already been addressed. I think 2011 had nine Tar wells that had an average 30-day rate of 178 barrels of oil per day. If I look at these latest three wells, looks like the average rate is 135 barrels of oil per day. It looks like that’s about a 24 percent decrease. Is there any reason why these wells came on at a lower rate? I mean what was the high and the low rates for your three Tar wells that came on.

Steve Heiter

The lowest one is about 60 to 70 in that range, and the higher ones are in the 140 to 150 range and these wells are step-out well. I think if you’ve been on the call for the last three of four calls, we continue to find additional development opportunities in the Tar. We thought we’ll be finished a year ago.

We continue to find more wells as we go further and further out towards the North West, in particular where we’ve had our best wells and to the east of the abandoning fall and we have had many pleasant surprises. And so we are continuing to start further and further out, so this isn’t a surprise. I think we put 90 barrels, 90 to 100 barrels in our plan for this year for the Tar wells, so this is not a surprise, but you are correct on the numbers.

John Abbott - Pritchard Capital Partners

All right, I appreciate it. Thank you.

Steve Heiter

Your welcome.

Operator

And your next question comes from the line of Jack Aydin of Keybanc. Please proceed.

Jack Aydin - Keybanc Capital Markets

Hey guys.

Steve Heiter

Hey Jack

Ron Morin

Hello Jack.

Jack Aydin - Keybanc Capital Markets

Tim, I’m looking at your cost structure, it looks like it continues to go up; I mean the LOE, the DD&A, G&A. What should we expect? Why those costs are not coming down going forward.

Tim Larkin

Well, I’m not so sure I completely agree with the statement Jack. I’ll take them one at a time and then I’ll let Steve jump in. DD&A went up because of the increased development cost on a per barrel basis at the end of 2011 and additionally it went down because we had a negative re-vision to our natural gas PDPs at the end of 2011. And so, we would expect that DD&A rate to remain constant for the balance of the year and not increase.

G&A we’ve hired some additional people and we are staffed up to commence drilling in both the WTU and the NWU and on an LOE basis, Lease Operating Expense basis as Steve mentioned, in the field we’ve done a very good job of getting prices down. However, we have items like, we have an ad valorem tax in California, which is a tax based upon what the state of California tells you the value of your reserves in the ground are. And so on a positive note, the State on California is valuing our reserves at a higher level on both barrels on the ground and pricing. On a negative note, we have to pay more taxes to California.

Jack Aydin - Keybanc Capital Markets

Okay, to follow on your DD&A, okay, you got 20 to 25 BOE equivalent and you listed three items. A future estimate of course, reduction improvement reserve and new drill break (ph). Can you break down that for me, how much each contributed to that 25 per barrel.

Ron Morin

I would say the estimated future development costs contributed 70% of the increase and a negative revision to the National Gas PDPs resulted in 30% on the increase.

Jack Aydin - Keybanc Capital Markets

Okay, I appreciate it.

Steve Heiter

Thanks John.

Operator

And your next question comes from the line of Brad Heffern of RBC Capital Markets. Please proceed.

Brad Heffern - RBC Capital Markets

Good morning guys.

Steve Heiter

Good morning Brad.

Brad Heffern - RBC Capital Markets

A quick question about the Niobrara; can you talk a little bit more about where we are in the process with the study and whether you guys are still thinking of drilling a well sometime this year. I saw that Double Eagle had some good oil shales from the well that they announced in March. How does that sort of affect your thinking on it?

Norman Swanton

Maybe I’ll take that one, this is Norman. We are taking a wait and see position. There is other activity as you may know, just the south of us going North West toward us from other operators with decent IPs and EURs and I think that our focus in terms of entry in capital has been going from the well concept stage to true drilling inventory in the Wilmington filed.

And with gas prices, we are minimizing any financial support in that regard, just keeping things going. So our priorities dictate that the wells performing, the new wells, they are getting as much as more economic. We are directing our capital in that regard and also we are starting to have discussions of various kinds with various parties about potential approaches, but it was just really a priority to get going in California and build an increasing base of production, so we can then look at our other assets and our other opportunities.

Brad Heffern - RBC Capital Markets

Okay, thank you.

Norman Swanton

Thank you.

Operator

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

Norman Swanton

Thank you very much for attending and have a very good day.

Operator

This concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.

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