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Executives

Norman Swanton - President & CEO

Tim Larkin - EVP & CFO

Ken Gobble - President & COO

Analysts

Leo Mariani - RBC Capital Markets

Warren Resources, Inc. (WRES) Q3 2010 Earnings Call November 3, 2010 10:00 AM ET

Operator

Good day ladies and gentlemen, and welcome to the Third Quarter 2010 Warren Resources Inc. Earnings Conference Call. My name is Sheena and I will be your coordinator for today. At this time all participants are in a listen only mode. (Operator Instructions).

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today Mr. Norman Swanton Chairman and CEO of Warren Resources. Please proceed.

Norman Swanton

Welcome ladies and gentlemen to the Warren Resources third quarter 2010 financial and operating results conference call. I am pleased to be here with Tim Larkin, our Executive Vice President and CFO, Ken Gobble our COO and President of our Operating Subsidiary Warren E&P is also joining us to discuss our operating results. Before I turn the microphone over to Tim to cover the financial results and Ken to discuss our operating results, I would like to briefly review some third quarter 2010 highlights.

Not only do we have an excellent financial third quarter but also had some important operational developments during the quarter. During the third quarter of 2010 our oil and gas production hit a record 2.8 Bcfe and revenue increased 41% to 23.1 million compared to the third quarter of 2009.

Our net earnings per share were $4.3 million for the quarter or $0.06 per diluted share compared to net income of 2.2 million for the third quarter of 2009 or $0.04 per diluted share representing a 99% increase in comparative earnings.

This is especially notable since net income for the third quarter of 2010 was decreased by a non-cash, mark to market derivative flaws of 2.4 million or $0.03 per diluted share. Warren's third quarter oil production volumes exceeded by 10,000 barrels, the high end range of our previously provided production guidance of 255,000 barrels of oil.

Our third quarter oil and gas revenue was 23.1 million of which 18.3 million or approximately 80% was from oil production.

Our continued focus of managing our operating costs along with improved oil prices allowed us to generate a gross margin of approximately $53 per barrel after LOEs during the current quarter. I'm also very pleased with our drilling results in our California Wilmington Townlot Unit or WTU which showed significant over the prior year's seven-spot water flood drilling program in the upper terminal formation.

Our new successful 3D geological reservoir of modeling combined with a high tech horizontal and sinusoidal drilling is translating into building a large horizontal and sinusoidal oil drilling inventory with strong economics, production growth and reserve bookings.

For example recent results from drilling our first proof of concept sinusoidal horizontal well which targeted the J sand in the upper terminal formation in the WTU, should outperform an average vertical well conceded in the same formation by a factor of five to one or better and an all in drilling and completion cost of about $1.8 million for the sinusoidal well.

Should these results continue to unfold favorably, and I believe they will, the company should be able to expand its rates of production and reserve booking significantly in the Wilmington field. Since the resumption of drilling at the WTU in April 2010, the company has drilled and completed seven new horizontal producing wells and one water injection well in the Tar formation, one proof of concept sinusoidal horizontal well in the J sand in the upper terminal formation and one proof of concept sinusoidal horizontal well in the Asia Pac's sand in the upper terminal formation.

The seven new Tar wells and one upper terminal sinusoidal well completed earlier this year are currently producing approximately 768 barrels of oil per day in the aggregate. I'm also pleased to report that on August 26, 2010 we purchased an all electric, sound proofed oil drilling rig which was specially designed with air bearings for rapid rig moves in the WTU. The rig is currently being shipped and will be assembled at the WTU.

Under the purchase agreement, the Company paid $7.0 million, consisting of a cash payment of $3.5 million and a balance of $3.5 million will be payable over 15 equal monthly payments commencing in September 30th, 2010.

Since the new rig will not be available for drilling at the WTU until approximately January the 2nd, 201, we have moved the additional four WTU wells that were planned to drill during the fourth quarter of 2010 to 2011.

Therefore during the first quarter of 2011, the company plans to drill and complete 4 gross, 3.9 net additional wells in the WTU that we originally planned for the last two months of 2010. It will consist of two sinusoidal wells targeting the J sand and Hx sands respectively in the upper terminal formation, one sinusoidal proof of concept well in the ranger formation and one additional Tar horizontal well.

On the natural gas side of our business, even though we have not drilled any new wells in 2010 in our Atlantic Rim, Coalbed Methane Natural Gas Project in Wyoming, our fracture stimulation program and well optimization increased our natural gas production by 23% to a record 1.3 billion cubic feet equivalent or Bcfe compared to 1.0 Bcfe in the third quarter 2009.

Our liquidity position is strong and I continue to believe that our long-term outlook has never been better. We will continue to build an environmentally-sound foundation to deliver strong growth and domestic production reserves and profitability for the years ahead in our core U.S. drilling areas. 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 third quarter 2010 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 of the forward-looking statements are described in our Forms, 10-K and 10-Q, other periodic filings with the SEC and our press releases.

As Norman mentioned, we had a very strong third quarter. Cash flow from operations continued to improve our balance sheet and liquidity position. Also we placed seven tar wells and one upper terminal sinusoidal well on productions since we recommenced our oil drilling program in April 2010.

The results have been encouraging. As of September 30, 2010, current assets exceed current liabilities by approximately $5 million. And we have $37.5 million available under our senior credit facility. We have now paid down $32.5 million of debt under the facility during the last 12 months.

Lastly, even with the acquisition of an oil rig for $7 million, which Ken will discuss in more detail, we expect to fully fund our 2010 capital expenditures with cash flow from operations.

Today, we reported net income of $4.3 million for the quarter or $0.06 per diluted share and adjusted net income of $6.7 million or $0.09 per diluted share excluding non-cash unrealized losses from hedging activities of $2.4 million.

Additionally, during the quarter, we generated $16.1 million of cash flow from operations, an increase of 178% over 2009. Also, we increased our oil and gas production to a record 2.8 Bcfe or 31 million cubic feet equivalent per day for the quarter.

Production from our two oil fields in California totaled 265,000 barrels during the third quarter, a 17% increase from the 226,000 barrels produced during the third quarter of 2009. Additionally, natural gas production, primarily from our Atlantic Rim project was strong and overall natural gas production increased 23% to 1.3 billion cubic feet during the third quarter compared to 1 billion cubic feet during the same period in 2009.

The average realized oil price for the third quarter of 2010 was $69 per barrel compared to $61 per barrel during the third quarter of 2009, an increase of 14%. Our third quarter Wilmington oil differentials for NYMEX prices were approximately $7 per barrel. Also during the third quarter, we had a realized gain from hedging activities of $1.7 million and unrealized non-cash mark-to-market loss from future hedges of $2.4 million.

As a reminder during the second quarter of 2010, when the price of the front month NYMEX contract for oil was below $70 per barrel the company repurchased 31% of its 2011 oil swap for $2 million. The 2011 oil swap had contract price of $61.80 per barrel. This reduced our 2011 swap from 1225 barrels or oil per day to 840 barrels per day or a reduction of approximately a 141,000 total barrels.

Then during October or 2010 we entered a NYMEX oil costless collars for calendar year 2011 for 700 barrels of oils per day or approximately 256,000 total barrels. The floor price is $70 a barrel and a sealing price of a $101 per barrel.

On average realized gas prices for the third quarters were $3.87 per Mcf compared to $2.71 per Mcf in the third quarter of 2009, as a result of increased oil production and improved commodity prices, oil and gas revenues for the third quarter increased 41% to $23.1 million compared to 2009.

Total operating expenses increased 28% to $17.3 million during the third quarter 2010 compared to 2009. Lease operating expense increased 33% to $7.7 million due to increased maintenance and plugging and abandonment projects in California. We expect LOEs to average approximately $17.50 per net barrel in 2010.

DD&A for the third quarter increased 7% to $5.6 million compared to third quarter 2009. DD&A was $1.97 per Mcfe during the third quarter of 2010 compared to $2.21 per Mcfe during the third quarter of 2009. This decrease in DD&A on a per Mcfe basis resulted from a lower estimated future development costs as of September 30, 2010 compared to 2009.

General and administrative expense increase 60% to $4 million during the third quarter of 2010. This increase resulted from a 1 million incentive compensation accrual recorded during the quarter relating to our 2010 year-end incentive compensation plan. Also during the third quarter the company recorded a non-cash share based compensation expense of $437,000. Interest expense decreased 46% to $896,000 as we continue to pay down our outstanding balance on our credit facility as previously mentioned.

Net cash provided by operating activities was $16.1 million during the third quarter of 2010 compared to $5.8 million during the third quarter of 2009. We have adjusted our forecasted 2010 capital expenditure budget from $36.5 million. This includes expenditures of approximately $22 million for our oil fields in California and $6 million for our Atlantic Rim natural gas project in Wyoming and other gas projects. This budget does not include the four oil wells originally scheduled to be drilled during the forth quarter of 2010 which will now be drilled in the first quarter of 2011.

The 2010 budget also includes acquiring an oil drilling rate for approximately $7 million and purchasing additional working interest in Doty Mountain and Catalina units in the Atlantic Rim project for $1.7 million. As previously mentioned, we expect to fund our 2010 capital expenditure budget with cash flow from operations.

Our borrowing base under our credit facility is $120 million. The next re-determination is scheduled through this month.

Currently, Warren has availability of $37.5 million under the credit facility. The company intends to continue to pay down debt if cash flow continues to exceed capital expenditures. This will reduce future interest expense while increasing the company's availability of funds under the facility.

Due to our strong liquidity position and the lenders' fees associated with increasing borrowing base, we did not ask our lenders for a borrowing base increase in November 2010.

As mentioned, Warren has entered into certain oil & gas price swap contracts, costless collars and NYMEX to CIG differential swap contracts. As a result, the company has locked in a minimum level of cash flow from operations. Additionally, as the operator of the WTU and NWU oil assets in California and co-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 fourth quarter and full year 2010 production guidance in our press release disseminated this morning.

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

Ken Gobble

Thanks Tim. As previously mentioned, Warren has purchased proposed build rig to assist in the future development of the company's California oil properties. The new rig is designed to work efficiently over the drilling cellars constructed in the WTU. Warren is planning delivery of the drilling rig to the WTU in November. The company anticipates that may take six to eight weeks to assemble, test a new equipment and training personnel once all the components of the rig have arrived on the location before the company can begin drilling operations.

With these considerations in mind, Warren is now forecasting the drilling of the next four wells in the WTU to take place in early 2011. As Norman mentioned, the seven Tar formation well and the one J sand Upper Terminal well drilled earlier this year continue to provide encouraging results. The ninth producing well on this program was the second Chinese oil horizontal well that targeted the HX section of the upper terminal formation.

This well encountered good drilling shows for the majority of the horizontal lateral. While drilling near the end of the plane lateral the decision was made to drop the oil path down to test the potential of additional untested sands in the well. The lower untested sand section in this well encountered high-water guts. This well was recently plugged back in attempt to isolate the water production from the lower sands. Warren expects to have oil production results from this well in the next few weeks.

At this early stage, testing the horizontal exploitation concept of the upper terminal formation, we continue to be quite optimistic about the ongoing development potential of the WTU.

In the company's Atlantic Rim Project, Warren and his partners have fractured-simulated an additional 29 of the existing wells during the second half of 2010. Warren plans to stimulate another seven wells in the next two weeks to bring the second half total to 36 wells. 14 of the well stimulated in the second half were located in Doty Mountain and 15 of the wells were located in the Sun Dog Unit.

Production from the wells after stimulation continues to be brought back up slowly for sand control purposes. Of the 29 wells stimulated thus far 19 have been placed back on production. Gas production from both the Sun Dog and Doty Mountain units was negatively impacted during the third quarter and will continue to be negatively impacted in the fourth quarter as a result of these wells being offline during the stimulation process. This optimization program continues to yield excellent production growth in both units.

Warren plans to install four compressor in the Doty Mountain Unit in early 2011 to accommodate production growth from the stimulation program. Thank you and now I would like to turn the call back over to Norman.

Norman Swanton

Thank you Ken. Operator we will now take any questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). And your next question is from the line of Leo Mariani with RBC Capital. Please go ahead.

Leo Mariani - RBC Capital Markets

Hey, good morning here guys.

Norman Swanton

Good morning Leo.

Leo Mariani - RBC Capital Markets

Just wanted to get an update on where your gas layer is out of WTU right now.

Ken Gobble

The last number I saw was the below 50, it was 44 Mcf a day.

Leo Mariani - RBC Capital Markets

Okay and your limit is what like 92?

Ken Gobble

94.

Leo Mariani - RBC Capital Markets

Okay, so I imagine you have got plenty of wells left to drill. Doesn't look like it's going to impact you guys in the near future from bringing these new four wells on?

Ken Gobble

That's correct.

Leo Mariani - RBC Capital Markets

Okay, it looks like your first upward terminal sinusoidal well has held up pretty well. Can you remind us how long it's been on production?

Ken Gobble

It's been on production for four months and it IP it was a 20 day IP at 225 barrels a day and last meaning it's flattening out hyperbolically at currently 158 barrels a day.

Leo Mariani - RBC Capital Markets

Something that you guys are encouraged by that, you look into drilling a well here in the near future. Do you guys have an assessment of what you think your inventory maybe, this point of those upper terminal well?

Ken Gobble

We haven't announced, we keep adding to our inventory but we haven't really come out with a definitive number yet and I think we would like to get these additional four wells behind us and that was going to be in appropriate time to come out with some guidance on the extent of our drilling inventory.

Leo Mariani - RBC Capital Markets

Okay and I guess how about in the Tar. That's obviously a formation you have a lot more experience with. Do you guys have a updated inventory number there?

Tim Larkin

Yes if memory serves me right, we have approximately should remember Ken, it was about 14 to 20 and I believe that's still the case

Ken Gobble

Yeah, that may be a little aggressive. We feel real comfortable somewhere in that 8 to 12 range. No question.

Tim Larkin

And as we continue to drill we may be able to prove up additional locations there.

Leo Mariani - RBC Capital Markets

Okay. I guess just jumping over to the Atlantic Rim here, what is talking you guys to frac these wells and do you think you're getting a nice reserve bump here on these wells when you frac them?

Ken Gobble

Actual costs are running -- once we get that pump -- that first pump landed back in the hole about $140,000 -- $150,000 a well, provided the big unknown additional expense is how much (inaudible) problems we have because we're running the progressive cavity pumps, the sand really has the density to chew rogue, dune streams up which could increase that $140,000 -- $145,000 number. As far as a bump, yeah initially what we're seeing is that we're – the (inaudible) is heavily impacted on the zone that we've been producing out of. Most of these wells were adding first off the hole which should reserve growth. What we're seeing is production shifted more forward on the curb which does impact overall economics. It would really help with our present value numbers.

Leo Mariani - RBC Capital Markets

Okay. And I guess last question for you guys, just when's the update on your gas injection situation in California. Where are you at with the regulators right now?

Ken Gobble

We're going back -- this is a bit confusing. Hold with me for just a moment Leo. Maybe I can square this up for you. The initial CEQA document that we presented above the comment was an unmitigated negative declaration which means there was no mitigation required and there was no impact, no significant impact.

After running through the process and a tremendous amount of legal review the AQMD in California has asked that we come back with a subsequent mitigated negative declaration document. So right now we're revising the original document that was sent out to public comment. We would hope to have those provisions done in the very near term and re-circulate it. We do have some timelines given by the AQMD. I hate to throw them out there with where we've been with this issue to date but I can assure you that it is something that we continue to throw everything we have a and folks that are and resolving this issue and I do feel comfortable that will happen in '11. Hopefully the first half -- that only time will tell

Leo Mariani - RBC Capital Markets

Okay and maybe can you help us understand what the difference is between the mitigated and the unmitigated negative declaration?

Ken Gobble

Even though that ordinarily when you provide -- when you go through an environmental process, document process like this, there will be some impacts. Typically with the impacts you can mitigate the impacts to reduce the significance of the issues from the impacts. Although the negative debt implies that there are no impacts they're asking us to agree to certain mitigation, certain mitigation measures which will be included in the subsequent mitigated negative declaration document.

Leo Mariani - RBC Capital Markets

Got you. Okay. Thanks

Ken Gobble

Thanks Leo.

Operator

(Operator Instructions). There are no further questions. I would like to turn the call back to Norman Swanton for closing remarks.

Norman Swanton

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

Operator

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

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Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

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