Warren Resources' CEO Discusses Q1 2011 Results - Earnings Call Transcript

May. 4.11 | About: Warren Resources, (WRES)

Warren Resources, Inc. (NASDAQ:WRES)

Q1 2011 Earnings Call

May 4, 2011 10:00 AM ET


Norman Swanton – Chairman, President and CEO

Timothy Larkin – EVP and CFO

Steve Heiter – EVP; CEO, Warren E&P, Inc.


Phil McPherson – Global Hunter Securities

Brad Heffrin [ph] – RBC Capital Markets


Good day ladies and gentlemen. Thank you for your patience and welcome to the first quarter 2011 Warren Resources earnings conference call. My name is Fab [ph] and I’ll be your operator for today. At this time, all participants are in listen-only mode. Later we will conduct a question-and-answer session. If at any time you require operator assistance, please press star followed by zero and we will be happy to assist you. As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Mr. Norman Swanton, Chairman and CEO, Warren Resources. Please proceed.

Norman Swanton

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

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 the first quarter of 2011 and the future direction of the company.

Taking into account that we did not commence drilling until late in the first quarter of 2011 we had solid operating results in the first quarter of 2011. Our total oil and natural gas production for the quarter ended March 31, 2011 increased 1% to 406,000 barrels of oil equivalent or BOE, compared to 401,000 BOE for the first quarter of 2010.

Given the higher oil prices, which were partially offset by lower natural gas prices, our combined revenue increased 7% to $23.2 million for the first quarter of 2011 compared to $21.6 million in the first quarter of 2010.

We incurred a net loss of $529,000 for the first quarter of 2011, or $0.01 per diluted share. Net income for the quarter was negatively impacted by unrealized and realized mark to market derivative losses on oil and gas hedges, principally oil.

In total for the first quarter of 2011, these derivative losses decreased net income by approximately $5.8 million or $0.08 per share, which would represent an adjusted first quarter net income of $5.2 million or $0.07 per diluted share if they are excluded.

In any event, we are in the process of purchasing offsetting coal oil actions to limit further hedge losses from higher oil prices forecasted for 2011 and 2012. The current non mixed oil over $110 a barrel and California oil prices of over $115 a barrel, I expect to see our realized oil prices rise significantly throughout 2011.

Since commencement of our 2011 drilling program at the WTU in late March 2011, the company drilled and completed a second proof of concept (inaudible) horizontal well, the J-Sand in the upper terminal formation and one new tar horizontal producing well in a new area of development in to (inaudible) field. The newly drilled upper terminal well in the J-sand is currently averaging approximately 70 barrels of oil per day, which is in line with our expectations. Test results on the newly completed tar well should be available shortly.

In the next few weeks, we’ll be drilling sine-soil horizontal wells in the HX sand in the upper terminal formation and sine-soil proof of concept wells in the ranger formation. This has never been done before. The 2011 drilling results should define the scope and quality of the unbooked reserves in the Wilmington oil field.

Although we have been constrained by regulatory hurdles in California, I’m encourage that the newly revised approval procedures and organizational improvements in the California Division of Gas and Geothermal resources, or DOGGR, have resulted in recent breakthroughs in the permits approval process.

As Steve Heiter will discuss in more detail, we now expect to receive approvals for several water injection wells in the next one to four months. This should allow us in 2012 to bring back to align our 2011 production that has been temporarily shut in.

Similarly, after three years of work, the South Coast Air Quality Management district, or the AQMD, has finally posted our SEQUA document for public comment. We have begun our 2011 drilling program in the WTU with our new rig. I feel confident that we will begin to see more consistent, wholesale production growth in the Wilmington field during the second half of 2011 and beyond.

On the natural gas side of our business, even though we have not drilled any new wells for the past two years in our Atlantic Rim natural gas projects in the Washakie Basin Wyoming, our fracture stimulation and well optimization programs increased our natural gas productions for the first quarter of 2011 by 10% to 1.2 billion feet equivalent of bcfe compared to 1.1 bcfe in the first quarter of 2010.

To remind everyone, we have previously identified 560,000 proof of methane well locations in the Atlantic Rim in the methane project. Additionally, we own 80,000 net acres in Washakie Basin below the CPM play, which is prospective for our barrel oil development. Wells will be drilled in the (inaudible) and tested in 2011.

Our liquidity position is strong and although we have had permitting challenges in 2011, I continue to believe that our long-term outlook has never been better.

With that, I’ll turn the phone over to Tim. Tim.

Timothy 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-K, other periodic filings with the SEC and our press releases

As Norman mentioned, we’re excited about 2011. Our cash flow from operations continued to improve our balance sheet and liquidity position. Also, we placed one upper terminal sinusoidal well and one tar well on production at WTU since we recommenced our oil drilling program in late March 2011.

We plan to continue to drill an additional ten oil producing wells and two injections wells in California. As of March 31, 2011, we have $50.5 million available under our senior credit facility. We have now paid down $45.5 million of debt under the facility over the last 18 months.

Additionally, we’ve acquired an oil drilling rig for $13 million including assembly costs. This rig was specifically manufactured for onshore drilling operations in southern California.

Today we reported a net loss of $579,000 for the quarter or a loss of $0.01 per diluted share and adjusted net income of $5.2 million or $0.07 per diluted share excluding realized and unrealized losses from hedging activities of $5.8 million

Additionally, during the quarter, we generated $7.7 million of cash flow from operations. Also, our oil and gas production was 406,000 barrels of oil equivalent for the quarter or 4,500 barrels of oil equivalent per day.

Production from our two oil fields in California totaled 210,000 barrels during the first quarter, a 6% decrease from the 223,000 barrels produced during 2010. As a reminder, Warren has had approximately 300 barrels of oil per day temporarily shut in due to water injection constraints.

Additionally, natural gas production primarily from our Atlantic Rim project in Wyoming was strong and overall natural gas production increased 10% to 1.2 billion cubic feet during the first quarter compared to 1.1 billion cubic feet during the same period in 2010.

Average realized oil price for the first quarter was $878 per barrel, compared to $71 per barrel during the first quarter of 2010, an increase of 24%. Our first quarter Wilmington oil differential from NYMEX pricing was approximately $7 per barrel.

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 bonus of $0.85 for the balance of our production. We currently produce approximately 2,300 net barrels of oil per day. Midway Sunset is currently selling at a premium to NYMEX.

Also during the first quarter, we had a realized loss from derivatives of $1.8 million and an unrealized non-cash mark to market loss from future derivatives of $3.9 million. Among our oil and gas hedges, the company owns a $61.80 NYMEX oil swap for calendar year 2011 at 840 barrels of oil per day or 231,000 total barrels from April 2011 to December 2011

The company also owns a NYMEX oil [costless collars] for calendar year 2011 with a floor price of $70 and a ceiling price of $101 per barrel for 700 barrels of oil per day or 192,000 total barrels from April 2011 to December 2011. Warren also owns January 2012 oil coal options with a strike price between $120 and $125 per barrel for 150,000 total barrels. This should partially offset derivative losses that may result if oil prices continue to increase.

Approximately 50% of our forecasted 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. On average, our realized gas price for the first quarter was $4.15 per mcf compared to $5.50 per mc in the first quarter of 2010.

As a result of improved oil prices, oil and gas revenues for the first quarter increased 7% to $23.2 million compared to 2010. Total operating expenses increased 13% to $17.4 million during the first quarter of 2011 compared to 2010.

Lease operating expense increased 7% to $7.7 million due to increased taxes and increased costs associated with plugging and abandonment projects in California. We expect oil LOE’s to average approximately $20 per net barrel in 2011.

Depletion, depreciation and amortization expense for the first quarter increased 28% to $6.1 million compared to the first quarter of 2010. DD&A was $15.11 per boe during the first quarter of 2011 compared to $11.92 per boe during the first 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 increased 3% to $3.6 million during the first quarter of 2011. This increase resulted from a $600,000 incentive compensation accrual recorded during the first quarter of 2011 relating to our year end incentive compensation plan. This increase was offset by lower non cash share based compensation expense, which totaled $358,000 for the quarter.

Interest expense decreased 35% to $571,000 as we continue to pay down the outstanding balance on our credit facility as previously mentioned. Additionally, the company capitalized $200,000 of interest relating to assembling the recently purchased drilling rig.

Net cash flow provided by operating activities was $7.7 million during the first quarter of 2011 compared to $8 million during the first quarter of 2010.

Our forecasted 2011 capital expenditure budget is $59 million. This includes expenditures of approximately $28 million for drilling 14 producing wells 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. Additionally, we forecasted $13 million for drilling gas wells, $3 million to drill an exploratory Niabrara oil well and $2 million for infrastructure costs related to our Atlantic Rim project in Wyoming.

As it mentioned previously, we expect to fund our 2011 capital expenditure budget primarily with cash flow from operations.

Our borrowing based under our credit facility is $120 million. The next re-determination is scheduled to be completed this month. 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 this re-determination.

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 second 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

Thank you Tim. Now I’d like to update Warren’s operational details. During the first quarter of 2011, we produced a total of 406,000 net barrels of oil equivalent consisting of 210,000 net barrels of oil from our Wilmington oil field and 1.2 net bcf of natural gas.

Warren’s new drilling rig is now fully assembled and operational in the Wilmington town lot unit. We spud the first well of our 2011 drilling program, a sinusoidal horizontal well in the upper terminal J-Sand formation on March 28. The well was placed on production on April 21 and is currently producing about 70 barrels of oil per day and 1,400 barrels of water per day. These are early test results and could improve as the well stabilizes.

The second well was drilled on fault block two to test potential tar D-1A reserves on the east side of the fault. The well was placed on production on May 2, and is currently being tested. The company currently has no reserves booked in the tar formation on this side of the fault.

We plan to follow these wells by drilling sinusoidal horizontal wells to test the Ranger formation and the upper terminal HX section. Once we have finished the first four wells, we may schedule a short pause in drilling activity in the WTU in order to assess the results prior to the second phase of our 2011 WTU development program. In total, we plan to drill 14 producing wells and two additional injection wells in the WTU in 2011.

During our last earnings call on March 4, 2011, we reported delays in the process of permitting new injections wells in the WTU. The California Division of Oil, Gas and Geothermal Resources adopted a more rigorous permit approval process during 2010. Additional required information and a new format resulted in previously submitted applications having to be re-submitted, which delayed permit approvals.

This, in combination with California State budget cuts, reducing the agency’s available man hours, had resulted in a back log of pending injection well permit applications. However, newly revised approval requirements and the OGGR organizational improvements have resulted in recent breakthroughs in the approval process.

We now anticipate approval of several injection wells in the next one to four months. In the meantime, we have implemented water hauling from WTU to our other unit, NWU, in order to minimize the impact of delayed injection permits at WTU.

The company’s long term plan to handle natural gas associated with increasing oil production from the WTU was originally presented to the south coast Air Quality Management District or the AQMD in March of 2008. After over three years of analysis, revision and development, our draft subsequent mitigated negative declaration pursuant to the California Environmental Quality Act was finally posted for public comment by the AQMD on April 26.

Unless the AQMD extends the 30 day comment period, the public will have until May 25, 2011 to submit comments to the AQMD. Warren and the AQMD will then work together to provide the appropriate responses to any comments. Assuming no additional delays, the document could then be certified and the permits issued shortly thereafter. Warren will then begin installing the new processing and gas handling equipment at the WTU.

In the company’s north Wilmington unit, we have committed $7.8 million of capital to upgrade the production and water handling facilities. This work should be finished in late 2011 in order to accommodate anticipated increased oil production from NWU when drilling activity resumes in early 2012.

We have approximately 20 available drilling locations at Satellite 7 and are evaluating the positioning of a second central drilling site for future NWU horizontal development.

Warren and the other working interest owners are in the process of forming the new larger Spyglass Hill unit in the Atlantic Rim. Spyglass Hill consists of approximately 113,000 acres and will include the areas previously committed to the Dobie Mountain, Sun Dog, Jack Sparrow and Brown Cow units as well as all additional leases to the southern portion of the project area.

This new unit will allow more efficient development and utilization of existing water and gas transportation infrastructure along with better protection on leases and acreage in the area. The Catalina unit will remain unaffected by the formation of the Spyglass Hill unit.

Warren plans to participate in the drilling of up to 25 gross or 10.3 net new wells in the Spyglass Hill unit and up to 20 gross or 2.7 net new wells in the Catalina unit in 2011.

We continue to evaluate the potential of Warren’s Atlantic Rim acreage for Niobrara oil development and are currently considering various alternatives including drilling our own well, joint ventures and joint participation agreements. We expect to share more specific details over the next couple of months as we finalize discussions with potential partners.

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

Norman Swanton

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

Question-and-Answer Session


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

Phil McPherson – Global Hunter Securities

Hey good morning gentlemen. Nice job on the quarter. A couple of quick questions; when you’re talking about the AQMD process, if you have comments, then do you have to post it again for another 30 days or once you’ve responded to the comments, then does it go to the permitting process?

Steve Heiter

Once we respond to the comments they are attached as part of a sequel document in the appendix and that document goes directly to the executive director, Mr. Wallenstein for his approval and there are no additional postings beyond that.

Phil McPherson – Global Hunter Securities

So May 25th is the day that you don’t – you get a response. You re-submit. Then is it applicable like 30 days later that the permit could be basically issued?

Steve Heiter

Well probably going to take us at a minimum two months is my guess to respond to comments depending on the quality of the comments. We have gone through this before and it took about two months and if the comments are good, they’re easy to answer. Some of the comments are way out there and it takes a little bit if ingenuity to answer them because they’re really not relevant.

And so it just depends on the quality of the comment, but we’re planning maybe two months for the responses and then we’re not sure how long it will take the APMD internally to get that up to the executive director and have him look at it. But we’re anticipating this to be a two to three month process once we start responding to the comments.

Phil McPherson – Global Hunter Securities

So hopefully on the second quarter call in August, you guys could be announcing that you’ve gotten the permit.

Steve Heiter

It could be close

Phil McPherson – Global Hunter Securities

And Steve, these permits with the use, you’ll use the gas. Will that eventually lower your operating costs from the field, some of the associated gas that you have with the field, will be you able to use that or you just basically selling it or what?

Steve Heiter

Well we’re using it now. I think as you know Phil, for the micro turban some of it by hand, we may install more micro turbans. I think the long range plan continues to be gas sales. We have to get our gas production up a little bit, but we have already started the planning for gas sales because I think in the long run, that’s the right thing to do and I’m not sure how long that’s going to take. It could be a couple of years. But that’s the long term plan, in which case it would be sold.

Phil McPherson – Global Hunter Securities

Got you. Great. And I wonder if you guys could comment on hedging and what you’re thinking kind of going forward. Obviously you’re not that levered right now but I think in 2012 your hedges kind of roll off and are you thinking about adding anything on the oil side or on the gas side with the recent kind of move in gas prices.

Norman Swanton

This is Norman. I think that our view is that hedges should be used to protect the downside of the commodity price. When you go into a swap, you really have two things; you have a put embedded to protect the down side, but you’re short of call and if the commodity prices run through your ceiling, you’re booking losses.

So we are well on the way to completely offsetting these swaps and actually one swap and two cashless collars where the ceilings are $101 and one when it was 6.5 and the other, so those could be offset with calls so you have short call, long call, which neutralizes it. And that’s how we’re planning to proceed in the future.

We’re going to protect the downside, but we want to keep the upside open for higher oil prices and spikes.

Phil McPherson – Global Hunter Securities

Got you. Got you. And Tim can you walk through that contract with the Conoco thing again. It was a little quick and I couldn’t catch it all about the differential and how it kind of works out.

Timothy Larkin

Sure Phil. We have a contract with Conoco Phillips that runs through July 2012 and basically the first 1,800 barrels that we produce, we sell to Conoco Phillips at 87% of the average NYMEX price for the month. And the balance of our production, which is currently approximately 500 barrels, which will grow as we continue to place wells on production during 2011, that additional production Phil, is sold to Conoco Phillips at the posted Midway Sunset price plus a bonus of $0.85 per barrel. And as you know, since you’re in California, Midway Sunset is now trading at a premium to NYMEX.

Phil McPherson – Global Hunter Securities

Got you. And at what point will you guys look to extend that contract or how does that kind of work? Is there an automatic option to renew it or do you go into like a conversations of shrinking that differential to NYMEX or how does that kind of work?

Timothy Larkin

Well the contract expires in July 2012 and you know at that point we will – there are a number of refineries in the area so my guess is that we’re, with the help of our oil marketer, we’re going to negotiate a new contract that would have the most favorable terms for the company.

Phil McPherson – Global Hunter Securities

Great. I appreciate it guys. Good luck on getting your permits.

Timothy Larkin

Thanks Phil.


And our next question will come from the line of Brad Heffrin [ph] from RBC Capital Markets.

Brad Heffrin [ph] – RBC Capital Markets

Good morning guys.

Norman Swanton

Morning Brad.

Brad Heffrin [ph] – RBC Capital Markets

On the most recent J-sand well, I was wondering if you could sort of go through the difference between that well and the previous J-sand well that you guys drilled last year and sort of what the difference in flow rate is. I know you said it was sort of in line with expectations. I’m curious why the expectation is a little bit lower for that one.

Steve Heiter

This is Steve. We’ve modeled these various sands and the model for the J-sand was – the current production is within that model range. Now obviously it’s not as good as 2161, which is the first well we drilled a year ago, but that was way outside the boundaries of our model and the way we look at this, we’ve drilled three wells and one very good, one that we just put on in the middle and one that we’re going to probably have to re-complete because it’s mostly water.

And if you put all those together and run economics on it, you get less than a year payout and over 100% return on investment, which is better than what we had forecast when we started this. So we expect to drill more wells in the high range, more wells in medium range and we expect some dogs and because of the history of the field with the very high water flood activity over the last 50 to 60 years, that’s what we expect to see and that’s what we’re seeing.

Now on this particular well, it should have been better production but we experienced some mechanical problems when we completed the well. We had some breakdowns and we think we’ve addressed those with the vendor and we didn’t get as good a gravel pack as we had gotten on all the other wells and we think we’ve got that taken care of.

So that’s kind of a summary where we’re at and we’re a little disappointed in the 70, but based on the problems we had at the end, I think it’s acceptable and it may even increase. We saw some of the wells we drilled last year, three or four months after they were put on and stabilized, production was still increasing. And so every well is different and we’re going to play around with this one and it still hasn’t stabilized. Pressure is still coming down. So that may not be the final initial production.

Brad Heffrin [ph] – RBC Capital Markets

Okay, great. And then shifting over to the injection permit, you kind of said recent breakthroughs in the press release. I was wondering if you could sort of go through any specifics around what particularly is different than what we sort of talked about on the fourth quarter call.

Norman Swanton

Sure. Division of oil and gas was resource constrained. They didn’t have enough people and operators had been submitting injection permits for a couple of years with no results and they have not only increased the number of staff, but I think the quality of staff and they have also changed their permit process where they’re allowing the operators to present good engineering judgment on an individual basis of these approvals.

And it’s working out really to our benefit because it’s not just black and white on these old abandoned wells that have been abandoned over the last 60, 70 years. We’re able to present an engineering case, which will allow some of these wells to be approved that may not have been approved otherwise. And it’s the right thing to do.

All the operators are going through it and we submitted originally 14 wells for approval and we’re in the process of resubmitting those because of the new requirements. We have to do the area review. I think you’re aware of that, within a quarter mile. All the schematics – we have built thousands of schematics for all the abandoned wells.

But the main point is better people at the DOG and a better approval process, allowing more of these abandoned wells to be acceptable based on good engineering judgment. But we have to prove it and we’ve got two wells right now in the tar formation that I think are very close to being approved.

Brad Heffrin [ph] – RBC Capital Markets

Okay. Great. And then I noticed that you mentioned these 34,000 gross acres outside of the Spyglass Hill unit. Is that also prospective for the Niabrara in addition to the other 80,000 acres that you guys have talked about?

Steve Heiter

Brad, the 24,000 net acres outside of Spyglass unit is part of the 80,000.

Brad Heffrin [ph] – RBC Capital Markets


Steve Heiter

And yes it is prospective for Niabrara.

Brad Heffrin [ph] – RBC Capital Markets

Okay, great. That’s it. Thanks.

Steve Heiter



There are no further questions in the queue. I would now like to turn the call back over to Mr. Norman Swanton for closing comments.

Norman Swanton

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


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

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