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Warren Resources, Inc. (NASDAQ:WRES)

Q4 2012 Earnings Call

March 6, 2013 10:00 AM ET

Executives

Philip Epstein – Chairman and CEO

Tim Larkin – EVP and CFO

Bob Dentici – Operations Manager, California Operations

Bob Dowell – Drilling Manager

Analysts

Raymond Deacon – Brean Capital

Kim Pacanovsky – MLV & Company

Gabriel Daoud – Sidoti & Company

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter and Full-Year 2012 Warren Resources Earnings Conference Call. At this time, all participants are in listen-only mode. Following the prepared remarks, there will be a question-and-answer session.

(Operator Instructions)

I would now like to turn the presentation over to Mr. Philip Epstein, Chairman and CEO of Warren Resources. Please proceed.

Philip Epstein

Thank you Stephanie, and good morning everyone, thanks for joining Warren’s fourth quarter and full-year financial operating conference call. First of all, I just want to mention that we have our new website up and running. It’s got great information as a fresh look. It’s taken a little bit of time to bring it into the 21st century, but here we are.

And if you take a look and look at the assets, and the operations of our community involvement, I think it’s communicates a great deal about the company. So with me here in Warren’s New York headquarters is Tim Larkin, who many of you know, our Executive Vice President and CFO, and joining from our Long Beach office is Bob Dowell, who has been our drilling manager and done a great job out in California and now is the general manager for our California operations.

As you may know, I was elected Chairman and CEO in December, just three short months ago. But since then, we’ve been very busy and we’ve had a very productive time working with the company and all the people in it. My background as some of you might know is mergers and acquisitions, finance and law. Over the past 20 years, I helped successfully build a couple of what I'd call entrepreneurial oil and gas companies, both in the public and private space, started out with Belco Oil & Gas in 1992. Like Warren, Belco had some attractive waterflood oil operations and long life gas assets. This gave us a strong base of operations and helped us grow considerably.

My job with Belco and with other oil and gas and other energy companies I have been a part for the past 20 years was to help grow the companies principally through my efforts through profitable acquisitions, joint ventures, and farm outs. And based on this experience, the Board selected me to execute Warren’s growth strategy. This is how I think of Warren. We are 65% oil by reserves, 65% PDP and PDNP by reserves, and our enterprise value was 65% of our PV-10. 65%, 65%, 65%. We have strong cash flow from our California operations. Our bank debts only 20% of PV-10 of our assets.

We ended 2012 with proved reserves of 16.4 million barrels of oil and 51 Bcf of natural gas. We have a drilling inventory of 160 locations in California and we have a large expansive what I would call gas farming operation in our CBM project in Wyoming though we have good assets, good cash flow, strong and motivated management, and a flexible balance sheet.

All of these in my mind are measures of a strong platform for growth. That’s the basis of our excitement here and the reason we’re confident we can increase our share price and deliver shareholder value.

Before I turn the mic over to Tim to cover the financial results and Bob to discuss our oil and gas operations, let me make a few brief comments on 2012 performance. Warren had a strong year at sales volume, oil and gas revenues, operating cash flow and reserves each recorded significant gains, 2012 was a record breaking year in terms of oil and gas production. Oil production increased 22% to 1.1 million net barrels of oil and gas increased 10% to 5.5 net Bcf, these generated over $120 million in revenues.

Importantly, as Bob will discuss our drilling cost for California wells dropped substantially. As a result of drilling 17 new wells in California, our proved oil reserves increased by 9.5% to 16.4 million barrels. And Warren executed on a timely low cost acquisition from Anadarko Petroleum in our Wyoming and Atlantic Rim coalbed methane project. This is a great asset. Also, we took over operations in that asset of the Spyglass Hill Unit and increased our proved gas reserves by 17% to 51 Bcf.

Our operating environment improved during 2012 as our California team worked effectively with the regulatory authorities in a proactive and positive way. For example, we obtained seven water injection permits during 2012, which will allow us to drill ahead in 2013. We expect to maintain positive cash flow after CapEx during 2013. This will provide us with the additional liquidity to execute on our growth strategy.

As the new operator of our CBM field in Wyoming, we are now maximizing returns from this large natural gas asset by affecting cost savings and new completion techniques as well as evaluating the deeper stacked paid potential underlying our large 88,000 net acreage position, which includes the potential for the Niobrara formation. As a result, Warren is in a great position to exploit our existing proved reserves, and actively seek out attractive acquisitions where we can leverage our expertise and enhance the oil recovery, horizontal drilling technology, and complex natural gas reservoirs to increase shareholder value.

With that overview, I’d like to turn the call over to Tim, our CFO.

Tim Larkin

Thanks, Philip. 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 facts 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 Philip mentioned, we’re excited about the balance of 2013 and beyond. Our cash flow from operations continues to be strong. We generated a positive cash flow after capital expenditures, which puts us in a strong liquidity position. We generated cash flow from operations of $14.2 million for the fourth quarter and currently have $40.5 million available under our senior credit facility.

Today, we reported net income of $4 million for the quarter or $0.06 per diluted share, and adjusted net income of $3.2 million excluding gains from hedging activities of $800,000. Also, we produced 580,000 barrels of oil equivalent for the quarter or approximately 6,300 barrels of oil equivalent per day. We produced 273,000 net barrels of oil in the fourth quarter or approximately 2,950 net barrels of oil per day compared to 247,000 net barrels produced in the fourth quarter of 2011.

Additionally, natural gas production primarily from our Atlantic Rim project in Wyoming was strong and overall natural gas production was 1.84 billion cubic feet during the fourth quarter compared to 1.3 Bcf in the fourth quarter of 2011.

The average realized oil price for the fourth quarter of 2012 was $94 per barrel compared to $92 per barrel during the fourth quarter of 2011, an increase of 2%. The average realized price for natural gas for the fourth quarter was $3.33 per Mcf compared to $3.47 per Mcf in the fourth quarter of 2011, a decreased to 4%.

The company sells its oil at the Midway Sunset posted price less then approximate $4 per barrel discount. Midway Sunset is currently selling at a $10 premium to WTI. As a result Warren is currently receiving a $6 premium to WTI.

Also during the fourth quarter, we recorded a net gain from derivatives of $800,000 which was comprised of a realized loss from derivatives of $1.2 million and an unrealized gain from future derivatives of $2 million. In order to protect the company against the decline in oil prices but allowing for an unlimited upside to oil prices. The company owns Brent puts for approximately 1375 barrels of oil per day with a strike price of $70 per barrel through September 30, 2013.

The company also owns NYMEX natural gas swaps for 7 million cubic feet a day at $3.39 for 2013 and $3.79 for 2014. As a result of increased oil production oil and gas revenues for the fourth quarter increased 17% to $31.9 million compared to 2011. Total operating expense is increased 38% to $27.8 million during the fourth quarter of 2012, compared to 2011.

Lease operating expense increased due to increased well work over activity and increased ad valorem taxes in California. We expect oil LOEs is to average approximately 20 hours per net barrel for 2013. Depreciation, depletion and amortization expense for the fourth quarter increased 27% to $12.6 million compared to the fourth quarter of 2011.

DD&A was $21.73 per BOE during the fourth quarter of 2012, compared to $21.45 per BOE during the fourth quarter of 2011. This slight increase in DD&A on a per barrel basis resulted from increased estimated future development cost associated with our proved undeveloped oil reserves. These estimated cost increased from $198 million as of December 31, 2011 to $223 billion as of December 31, 2012.

General and administrative expense increased 24% to $4.9 million during the fourth quarter of 2012. This increase primarily resulted from $700,000 of stock option expense related to the accelerated vesting of equity, related to four former executive officers and employees. Additionally, consulting expense increased $400,000 during the fourth quarter of 2012 compared to 2011. Interest expense decreased 22% to $900,000 during the current quarter, due to a decrease in the amortization of deferred offering cost relating to our credit facility.

For the full year 2012, we reported net income of $15.5 million or $0.22 per diluted share. And adjusted net income of $18.5 million excluding losses from hedging activities of $3 million. Additionally, during the year, we generated $67 million of cash flow from operations. Our oil and gas production was 2 million barrels of oil equivalent for the year or 5500 barrels of oil equivalent per day. The average realized oil price for 2012 was $96 a barrel compared to $92 a barrel during 2011. The average realized gas price for 2012 was $2.78 per Mcf compared to $3.98 per Mcf during 2011, a decrease of 30%. As a result of increased oil production, 2012 oil and gas revenue increased 18% to $122 million compared to 2011.

Total operating expenses increased 32% to $100 million during 2012 compared to 2011. The increase resulted from an increase in DD&A and G&A expense. DD&A was $23 per BOE during 2012 compared to $17 per BOE during 2011. This increase in DD&A on a per barrel basis resulted from higher estimated future development costs and lower natural gas reserves during 2012 compared to 2011.

Additionally, G&A expense increased $5 million primarily due to severance packages to the four former executive officers and employees. Our 2013 drilling and facilities capital expenditure budget is $58 million, $53 million related to our California oil fields and $5 million related to our Wyoming natural gas fields.

As the operator of the WTU and NWU oil assets in California and the Atlantic Rim project in Wyoming, the company has the ability to modify its capital expenditure budget as commodity and financial markets changed. We reported first quarter and full year 2013 production in our press release disseminated earlier this morning.

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

Bob Dentici

Thank you, Tim. Now I’d like to update Warren’s operational details.

In 2012, Warren drilled and completed 17 new producing oil wells and one injection well in the WTU consisting of five Upper Terminal Wells, three Ranger Wells and nine Tar Wells. 30-day initial production rates for the new Tar wells averaged just over 105 barrels of oil per day. These new Tar wells typically experience a 50% to 60% reduction in producing rates after a few months. This is a normal hyperbolic decline and results in our typical ultimate recoveries of 100,000 to 125,000 barrels of oil per well.

Project economics for the nine Tar wells indicate a nine to 12 month payout at $80 Midway Sunset pricing. 30-day initial production rates for the five new Upper Terminal Wells averaged about 85 barrels of oil per day and have experienced normal declines to date. Our two best Upper Terminal Wells drilled in 2012 averaged a 130 barrels of oil per day initially and expected ultimate recoveries are about 150,000 to 200,000 barrels of oil per well. Project economics for the five Upper Terminal Wells indicate a 14 to 16 months payout at $80 Midway Sunset pricing.

30-day initial production rates for the three new Ranger Wells averaged approximately 50 barrels of oil per day and these wells are experiencing normal decline rates. The addition of injections support should help maintain production from these wells in the 40 to 50 barrels of oil per day range and also meet recoveries are expected to be about 125,000 to 200,000 barrels of oil per well. Project economics for the five Ranger Wells indicate a 16 to 18 months payout at $80 Midway Sunset pricing.

During 2012, drilling costs were reduced on average 20% versus 2011. Changes to the well and our completion design, key process improvements increased experience levels of the crews and a comprehensive preventative maintenance program all contributed to this reduction. Warren continues to work with the AQMD to pursue gas sales as the preferred method of disposing excess gas produced at the WTU.

In August of 2012, the necessary permit applications were filed with the AQMD for the new equipment needed to condition the gas to meet sales specifications, the addition of these new facilities was slightly different from the gas sales facility assessed and the previous CEQA certification approved in 2011. Due to this change, the AQMD advised Warren, that a new supplemental CEQA assessment will be required. The supplemental CEQA assessment was started in September 2012 as anticipated to be approved by mid-year 2013, barring any unforeseen delays.

Upgrades to the production and water handling facilities are complete, and will accommodate the anticipated increased oil production from the NWU when drilling activity begins in April of 2013. We are in the process of completing our acquisition of additional lots around our NWU Central Facility for a second drill site, that will accommodate the remaining 20 to 25 wells in our NWU development plan.

The company has a 2013 capital expenditure budget of approximately $58 million, consisting of $53 million for California oil drilling activities, and $5 million for Wyoming activities. The 2013 capital budget for the WTU consists of $30 million for drilling, and $5 million for facilities improvement and other infrastructure costs. The 2013 capital budget for the NWU consist of $13 million for drilling and $5 million for infrastructure improvements.

During 2013, the company plans to drill 3 Tar horizontal producers, Upper Terminal sinusoidal producers, and 5 Ranger Sinusoidal producers in the WTU. Additionally, Warren plans to drill 3 Ranger Sinusoidal water injectors in the WTU. In the NWU, the company plans to drill 4 Sinusoidal producers, and 3 Sinusoidal injectors in the Ranger formation in 2013.

Warren issued a full reserves press release on Friday, I’m sorry, on February 6, 2013. To summarize, California oil reserves increased 9.5% to 16.4 million barrels of oil, compared to year-end 2011. The PV-10 of our proved oil reserves at year-end 2012 was $476 million, this reflects the results achieved during our 2012 drilling program.

Gas reserves for our Wyoming properties increased 17% during 2012 to 8.5 million barrels of oil equivalent with a $19 million PV-10 value of new. While the increase in our gas reserves was helped by our acquisition of natural gas production and reserves from Anadarko Petroleum Corporation in October 2012, the overall value was hurt by much lower gas pricing and some negative adjustments to production type curves. We continue to evaluate the potential of our Atlantic Rim acreage, but oil development in the Niobrara and other deep formations. We recently concluded a regional geographic study of the Niobrara formation and are considering the best options for development.

Thank you for participating today and I will now return the call to the operator for any questions.

Question-and-Answer Session

Operator

Thank you ladies and gentlemen, we are ready to open the lines for your questions (Operator Instructions). Your first question comes from the line of Ray Deacon with Brean Capital. Please proceed. Ray your line may be on mute, check your mute feature.

Raymond Deacon – Brean Capital

Yes, hi, good morning. I had a question about CBM activity this year. And what type of CapEx would you need to, to commit next year in order to hold off the federal units together there and are there any update on your thoughts on the Niobrara potential there.

Philip Epstein

Yeah, hi Ray, it’s Phil. Thank you.

Raymond Deacon – Brean Capital

Hi Phil.

Philip Epstein

So we’re evaluating the CBM Wyoming play. Prices out there are not robust but there’s still some pretty reasonable economics were we’ve actually brought on a very new strong manager. He comes to us from Samson, and [Arlington] [ph] and Mark West, his name is Scott Daves.

He’s going to be evaluating some pretty interesting new fracking techniques to increase production. There is a requirement to hold, to prevent the contraction of the units that we drilled 25 wells per year. Actually, it would run into per season so spring and then fall. So we’re evaluating that and seeing whether we should pursue that and at what cost we should pursue it at. We’ll have more information on that probably after the first quarter.

The deeper Niobrara potential is interesting that play has had some, some pretty big excitement and some not so big excitement in different areas. We have done a geological study. We have been, which is indicated to us that we have some very good Niobrara prospects on our acreage. That acreage is a very big unit. We’re taking steps to preserve the – our acreage in that unit for the deep potential whether or not the CBM contracts.

So, we’re taking steps to preserve our optionality there. And the other interesting thing about that is that there is a lot of stacked pays, it’s not just the Niobrara we can pursue. But there is 3 or 4 other formations, the Shannon, potentially the Sussex, the Dakota, the Frontier, there is a lot of stuff we can do there. So we’re pretty excited about preserving that and figuring out how to bring that – bring those hydrocarbons to the surface.

Raymond Deacon – Brean Capital

Okay, great. And maybe just one quick follow-up. What are – you had a pretty significant decline in your well costs in California last year, I guess. What are you assuming for this year sort of flattish or –

Bob Dowell

Hey, Ray, this is Bob Dowell. I’ll take a stab at that. No, what we’re anticipating is that we can achieve some further reductions in those costs implementing some of successes we achieved last year and then furthering those. Although, I don’t think you’ll see as large of a decrease, we’re challenged to continually lower our cost on these wells. And I would think you’d see at least the number we held last year are some were 5% to maybe 8% reduction in 2013 with those implementations.

Raymond Deacon – Brean Capital

Okay, great. And maybe just, Bob, one more follow-up. Any kind of update on asset – assets available around you, at the end of your WTU, I mean, did you see any opportunities to expand there?

Bob Dowell

Well, we’ve got a pretty aggressive plan that Philip has us evaluating, and it would include any and all outlying properties in the area. There are others looking at those as well, but we will continue to pursue those. And if the opportunity presents itself, I think it’s a good bolt-on to our success at both WTU and NWU to do those things.

Raymond Deacon – Brean Capital

Okay. Great, thanks.

Operator

Your next question comes from the line of Kim Pacanovsky with MLV & Company. Please proceed.

Kim Pacanovsky – MLV & Company

Hi, good morning everyone.

Philip Epstein

Good morning, Kim.

Tim Larkin

Good morning.

Kim Pacanovsky – MLV & Company

Kind of a big-picture question. Besides the bolt-on acquisition that you could do in California, you mentioned, Philip you mentioned your growth plan, what does this growth plan encompass? Are you looking at other areas or you looking to get into new plays and how much capital would you be willing to commit? I mean obviously you are in very good shape this year drilling out of cash flow. So what kind of growth – what level of growth could we expect to see in 2013, potentially?

Philip Epstein

Well, Hey Kim, that’s really the challenge and it’s a great question. This is a pretty interesting time from our perspective to pursue transformative acquisitions and also smaller bolt-on acquisitions. We’re not going to be looking at high risk exploration plays. We’re not going to be the first one to put the drill bit in the ground. We’re looking more at lower risk acquisitions with high PDP components, so we could add some leverage to the acquisition, and PUD potential which might not be that attractive right now or 2P potential given the price environment or for gas for example.

So we can literally and we’ve been scoping out quite a few transactions to do a deal anywhere from $50 million to $100 million to $200 million to $300 million. It all depends, of course, on what we’re acquiring and how much EBITDA is coming to us. And, but I want to emphasize that it’s not our intent to jump out ahead of the exploration curve. It’s our intent to find opportunities where we can apply our basic skills of enhanced oil recovery or CBM like plays or complex reservoirs.

So as – we’ve been talking to folks on the road that a play which we can buy on a PDP basis that yields to us on a leverage basis of 15% IRR with significant upside, if there is appreciation on commodity prices by virtue of the PUDs becoming economic and or deeper potential sort of like what happened with the Anadarko acquisition, looking at deeper zones. That’s the type of thing we’d like to look at.

Kim Pacanovsky – MLV & Company

Okay. And the Anadarko acquisition was accomplished at such a low cost, and I don’t know that there would be a repeat of that as there but, I guess it’s clear that you’re not afraid of gas here. You’re not afraid of buying gas if you see the upside?

Philip Epstein

Yeah, that’s, that’s correct. I think that gas offers greater opportunities. There is lot of companies that we’re into gas early and are looking for capital to expend on development of those plays, so we’re going to be looking at – jumping into development like programs. So if gas offers the returns that we’re targeting, we would do that and we’d hope to capture a large resource that way, so that in a couple of years, we can play it out and earn cash on cash returns and see if something good happens.

Kim Pacanovsky – MLV & Company

Okay. All right. Thank you and good luck.

Philip Epstein

Thank you.

Tim Larkin

Thanks, Kim.

Operator

Your next question comes from the line of Gabriel Daoud with Sidoti & Company. Please proceed. (Operator Instructions).

Gabriel Daoud – Sidoti & Company

Yes, thank you. Sorry about that. Good morning, everyone.

Philip Epstein

Good morning, Gabe.

Tim Larkin

Good morning, Gabe.

Gabriel Daoud – Sidoti & Company

Just a quick question on California in 2013, and if we could expect to see any Ford wells being drilled this year? And if not maybe on related to permitting issues in California.

Philip Epstein

I’ll jump just quickly, and Bob can follow up. It’s principally because of our desire to spend most of our CapEx on drilling producer wells and to a lesser extent injector wells. So it’s really, looking for near-term cash flow, coming out of those wells. And Bob, you want to elaborate on that.

Bob Dowell

Yeah, if I might. The proximity of those wells, we have 2 drilling sellers at our WTU facility and we prefer to drill these wells out of our Cellar 1 location, particularly at the South. And so, our drilling rig presently is on our cellar 2 location. So we’re going to drill over on cellar 2, and upon completion of the program this year, we will move our drilling rig back to our cellar 1 location, which positions us to drill those Ford wells.

In addition, that’s a much deeper zone and a larger zones, so our injection into that zone will require a kind of a booster pump if you want in our cell – into our cellar to put the injection water into that zone. So that facility upgrade is going to be completed this year. So we’ll be ready to have injection into the Ford at the same time, we’re drilling into the Ford. So those two things coupled with, as Philip described are the reasons, we’re not planning at this point to do a Ford development in 2013.

Gabriel Daoud – Sidoti & Company

Okay. So nothing at all then I guess maybe, we could see something next year, I guess or further into 2014?

Philip Epstein

Yeah. That would be the case. We have mapped out drilling inventory in the WTU and NWU of about 160 locations, and we’re sort of prioritizing the locations we’re drilling right now to maximize cash flow coming back, but it’s a robust inventory and if you will, we’re saving it for another day.

Gabriel Daoud – Sidoti & Company

Sure. Okay. And I guess just another quick question on Ranger wells, if you could just remind me on remaining inventory with that formation?

Tim Larkin

Yeah. As Philip just mentioned, we have a 160 and those are producing well locations. In our Ranger, we’re carrying about 17 well locations, in our inventory will drill 5 of those this year. And, we will drill 3 more injection wells, which should really help support the production in that Ranger of formations going forward.

Gabriel Daoud – Sidoti & Company

All right, perfect. Thank you so much, guys.

Philip Epstein

All right. Thanks a lot.

Operator

With no further questions in queue, I will turn the call back over to Mr. Philip Epstein for any closing remarks. Please proceed.

Philip Epstein

Okay. Well, thank you, Stephanie. And thank you everybody for joining this call. This was my first call and it was Bob’s first call, its Tim’s probably 18th calls. So, we’re very happy to – as everybody participating this call, this is – in three short months, as I said, I’ve learned a great deal about this company. It’s a great team. We have great employees, really smart employees. And we’re looking forward to a successful year. So thanks everybody. Have a good day.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect, and have a great day.

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