Warren Resources Inc., Q3 2009 Earnings Call Transcript

Nov. 4.09 | About: Warren Resources, (WRES)

Warren Resources Inc., (NASDAQ:WRES)

Q3 2009 Earnings Call

November 4, 2009 10:00 am ET

Executives

Norman Swanton - President, Chairman and CEO

Tim Larkin - EVP and CFO

Ken Gobble - President and COO, Warren E&P

Analysts

Mark Lear - Sidoti

Leo Mariani - RBC

Operator

Good day, ladies and gentlemen, and welcome to the third quarter Warren Resources Inc., Earnings Call. My name is Kiana and I will be your operator for today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator instructions)

I would now like to turn your call over to your host for today Mr. Norman Swanton, Chairman and CEO of Warren Resources. You may proceed.

Norman Swanton

Good morning, everyone. Thank you for joining us for Warren Resources’ third quarter 2009 financial and operating results conference call. I’m 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 from Wyoming to discuss our operating results.

Before I turn the microphone over to Tim to cover the financial results and Ken to discuss our oil and gas operations, I would like to briefly comment on the third quarter 2009.

I’m pleased to report that Warren Resources has weathered the storm of economic recession, credit crisis and low energy prices and returned to a path of solid liquidity and profitability. There is plans to resume drilling and development activities in the Wilmington oil field in California and the Atlantic Rim project in Wyoming during the first quarter of 2010.

As earlier reported in October 2009, we successfully raised $29 million in an equity public offering. Additionally our proactive program to improve our liquidity, by reducing operating expenses and reining in capital expenditures has made significant progress, as we generated positive cash flow from operating activities of $14.5 million for 2009 year-to-date.

We’ve identified additional drilling locations in our Wilmington Townlot Unit's Tar formation and are developing a highly targeted drilling inventory in the other major reservoirs in the Wilmington field.

Additionally we plan to increase our compression capabilities in our Atlantic Rim's Doty Mountain Unit in Wyoming and additional water injection rates in our Atlantic Rim's Sun Dog Unit, which should increase natural gas production significantly without drilling new wells.

Warren’s oil and gas production was 2.4 billion cubic feet equivalent or Bcfe during the third quarter of 2009, holding essentially flat from the second quarter of 2009 and a slight 4% decrease from the third quarter of 2008. Since we have not drilled any new oil and gas wells in 2009, I believe such a constant production level demonstrates the steady and long lived nature of our oil and gas assets.

As the economy slowly recovers from its recession, we witnessed continued pricing improvement for oil in the third quarter of 2009. Warren had averaged realized oil prices of $60.51 per barrel for the third quarter 2009, representing an increase of 12.5% from the average realized price of $53.81 for the second quarter of 2009, but 43% below the record $106.82 per barrel realized prices during the third quarter of 2008.

As we emerge from this difficult economic and commodity price environment, I want to commend and thank our dedicated employees who confronted the challenges and helped our company emerge as a more lean and focused enterprise.

Based on our recent operating results, I believe we are once again on our way to demonstrating this huge untapped potential of our oil reserves in the Wilmington Field units in California and the large natural gas reserves in the emerging Atlantic Rim coalbed methane project in Wyoming.

We will continue to prudently build upon this platform to resume growth in domestic production, reserves, and profitability for the years ahead.

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

Tim Larkin

Thanks, Norm. Before I discuss the company’s third quarter 2009 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 would 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 these 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 and other periodic filings with the SEC and our press releases.

As Norman mentioned, the third quarter of 2009 was a very good quarter for us. Additionally the October equity offering provides the company with the liquidity needed to resume development activities. We had net income of $2.2 million for the quarter while generating $5.8 million of cash flow from operations. We accomplished this simultaneously while reducing CapEx to $1.5 million for the quarter.

Also, we maintained production at 2.4 Bcfe or 26 million cubic feet per day equivalent. Production from our two oil fields in California totaled 226,000 barrels during the third quarter, a 14% decrease over the 263,000 barrels produced during the third quarter of 2008. Additionally, gas production from our Atlantic Rim project was strong and overall gas production increased 12% to one billion cubic feet during the third quarter compared to 906 million cubic feet during the same period in 2008.

The average realized oil price for the third quarter 2009 was $61 per barrel compared to a $107 per barrel during the third quarter of 2008, a decrease of 43%. Our Wilmington oil differentials from WTI prices were $7 per barrel during the fourth – during the third quarter.

Also during the third quarter we had realized loss from hedging activities of $593,000 and an unrealized non-cash gain from future hedges of $1.4 million. On average realized gas prices for the third quarter was $2.71 per Mcf compared to $6.42 per Mcf in the third quarter of 2008, a decrease of 58%. As a result of reduced commodity prices, oil and gas revenues for the third quarter decreased 52% to $16.4 million compared to 2008.

Total operating expenses decreased 21% to $13.5 million during the third quarter of 2009. Lease operating expense decreased 30% to $5.8 million due to a reduction in California and Wyoming lease operating expenses, primarily due to more focused operations.

DD&A for the third quarter was essentially flat when compared to the third quarter of 2008. DD&A was $2.21 per Mcfe in 2009 compared to $2.08 per Mcfe in 2008. General and administrative expense decreased 31% to $2.5 million during the third quarter. During 2009, Warren has reduced its payroll and consulting expenses.

Interest expense increased as we had a higher outstanding balance under our credit facility during the third quarter of 2009 compared to 2008. Net cash provided by operating activities was $15 million during the first nine months of 2009 compared to $56 million in 2008.

We have reduced our full year 2009 capital expenditure budget to $7.5 million. As mentioned in our press release yesterday, our lenders reaffirmed our borrowing base at $120 million. As of September 30, 2009, Warren had borrowed a $115 million under this facility. As previously mentioned, during October 2009, Warren affected a secondary equity offering generating net proceeds to the company of $29 million. Additionally during October 2009, the company paid down a $7.6 million tranche under its credit facility. The company intends to continue to pay down additional credit facility amounts as they become due. This will reduce interest expense while increasing the availability of funds.

As previously disclosed Warren has entered into certain oil and gas swap contracts. As a result the company is locked in a minimum level of cash flow for operations. As the operator of the WTU and the NWU oil assets in California and co-joint venturer 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 2009 production guidance in our press release – in our press release released during October.

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

Ken Gobble

I’d like to update Warren’s operational details. The company with its partners in the Atlantic Rim project plan to increase to produce water injection capacity in the Sun Dog Unit in the fourth quarter of 2009. Once this work is completed we are planning a nine well fracture stimulation program in Sun Dog that will take place early in 2010. The company and its partners also plan to increase the compression capacity in the Doty Mountain Unit before the end of 2009. Warren is planning to resume the successful fracture stimulation program in the Doty Mountain Unit in 2010. This will include the completion of the 13 wells that were drilled but not completed at the end of 2008.

At this time, the partners in the Atlantic Rim are not planning to drill any producing wells in 2010. However, Warren does anticipate significant gas production growth from a project area from its capital spending program. Warren continues to progress towards the resolution of the regulatory issues with the South Coast Air Quality Management District or AQMD’s restrictions concerning compliance with air quality standards and the permission to install the best available control technology equipment in the WTU.

The AQMD is currently awaiting a review from outside counsel on the answers to the comments that were received from the public on Warren’s environmental document or CEQA. This is one of the final steps before the CEQA document is certified and Warren’s permit applications are approved by the AQMD.

Warren is planning to resume drilling in the WTU in early 2010. The company will drill several locations offsetting the successful horizontal Tar development in the unit. The company is planning to focus future development in both the Wilmington Townlot Unit and the North Wilmington Unit’s Ranger formation by utilizing highly targeted horizontal drilling.

This development technique was used successfully in the six well Ranger pilots that the company drilled in 2008 in the North Wilmington Unit. The company now prefers this development strategy to the previously drilled inverted seven-spot water flood development utilized in the Wilmington Townlot Unit upper terminal zone.

Warren plans to review results from this new strategy of development prior to rebooking the undeveloped reserves that were removed at year end of 2008. The future development of these reserves will move forward cautiously and efficiently as the company continues to closely manage expenses and improved profitability.

Now I’ll turn the call back over to Norman.

Norman Swanton

Operator, we’ll now take any questions.

Question-and-Answer Session

Operator

(Operator instructions). Our first question comes from Mark Lear of Sidoti. You may proceed.

Mark Lear - Sidoti

Good morning.

Norman Swanton

Good morning, Mark.

Tim Larkin

Good morning, Mark.

Mark Lear - Sidoti

Just wondering, I’m sure you’ve been thinking about Townlot and kind of thinking what the plan looks like in Wilmington in terms of your drilling activity?

Tim Larkin

I’m sorry. Mark, what was the question?

Mark Lear - Sidoti

In terms of what kind of development plan you think you’re going to be executing out there in 2010.

Tim Larkin

I think, Mark, we’re going to start out by – we’ve identified approximately 12 target drilling locations and we’re going to start out by drilling those wells, analyzing the results and take it from there. As far as full year 2010 CapEx guidance, we’ll probably come out with that something in the beginning of 2010.

Norman Swanton

Ken, do you have anything to add to that or is that –

Ken Gobble

Well, not really, our staff out there has been working hard on a drilling inventory. We’re trying to develop approximately 54 strength prospects aimed at the horizontal type strategy that we intend to employ. I would think that we would like to see the results from the Tar development that Tim mentioned and really see what the balance of 2010 looks like before we really start going hard and heavy with CapEx out there.

Mark Lear - Sidoti

Just I guess comparing the two the Tar horizontals versus the Ranger’s sinusoidal project, how do the project returns compare between the two?

Ken Gobble

The sinusoidal project development is a little bit more expensive compared to the Tar wells. Those Tar wells are going about 1.5 million the last ones we drilled at. I hope that we can bring that down a little bit with the decrease in service costs that we’ve seen in the last few quarters. I would expect that sinusoidal to probably go somewhere in the $2 million range and of course that’s still a water flood type development strategy. So we will have some injection well expense on top of that. As far as [EURs] on the wells they are very similar. Max rates on the sinusoidal type we are modeling in that 60, 65 barrel peak range. Of course, I would expect that the – because the Tar’s more closely related to primary production and the sinusoidal wells would be more of a water flood style development, I would expect that the finds on the sinusoidal to be a little flatter than the Tar wells.

Mark Lear - Sidoti

Got you. Can you kind of update me on the progress with the ASP Pilot?

Ken Gobble

All of our lab works being completed, I would really like to see to us do a little bit of injectivity testing out there. But I would really hope that, that’s something. That we would plan to commence sometime in 2010 as long as the commodity prices still look favorable. Probably no question we would like to complete the work with the AQMD prior to really starting to get serious about permitting that project.

Mark Lear - Sidoti

What be I guess the price tag on the pilot that you would be looking at?

Ken Gobble

I would think total costs to implement a pilot probably be in that three million range maybe $3.5 million. If you look at the results – the last results from the cores that we took from the Ranger in the Wilmington Townlot Unit and if you look at some of the pilots that were ran in that those same rocks in the Wilmington Townlot Unit, I think that that capital spending exposes the company to a significant upside on reserves.

Even if we can just improve original oil in place recovery by 5% that’s approximately nine million barrels of recoverable oil just in the Ranger in the Wilmington Townlot Unit. So that’s something that we are still really excited about. I think it’s something that we would like to get started on sooner than later

Mark Lear - Sidoti

Is it just the Ranger that you’d be targeting with the chemical flood?

Ken Gobble

No. Not at all. I think the upper terminal water flood where we drilled that seven spot invert that’s probably where we will run our first pilot. So I think the – what would make sense as far as targets there – they will probably start with the start the pilot in the upper terminal seven spot invert and then start – once we see results from that seriously start exploring the possibility of both the Ranger and the North Wilmington and the Ranger and the Wilmington Townlot Unit.

Mark Lear - Sidoti

Got you. I guess just to touch on the hedging activity in 2010, I didn’t seen anything mentioned. Have you guys started to think about adding hedges with crude up here close to 80?

Ken Gobble

No, we still have about six million a day of our gas locked in through 2010. I think, we –

Tim Larkin

We’re monitoring, Mark, the – we’ve been looking at the costless callers and we’re – yes, we’re monitoring that activity very closely.

Mark Lear - Sidoti

So there has been nothing added at this point on the oil side?

Ken Gobble

Not, yet.

Norman Swanton

Nothing on the oil side. No. Just the gas right now.

Operator

(Operator instructions). Our next question comes from the line of Leo Mariani of RBC. You may proceed.

Leo Mariani - RBC

Good morning here, guys.

Norman Swanton

Hi, Leo.

Ken Gobble

Hey, Leo.

Leo Mariani - RBC

When do you folks anticipate starting your drilling program at the NWU?

Ken Gobble

Right now, we really don’t have any plans in the NWU for additional drilling in the short-term.

Leo Mariani - RBC

Okay. You guys – you mentioned 12 locations in the Tar at WTU. I think, you guys had some wells that were sort of drilled in the vertical stage, does that 12 number include those?

Ken Gobble

It does. There is four wells that we had set casing on previously, before we started slowing down into late 2008, Leo.

Leo Mariani - RBC

Obviously you’ve got the AQMD kind of going through your final review here, would you guys be able to start drilling without their approval, or do you feel you’ve got to get final approval on gas re-injection and then the flare out there before any wells can be drilled?

Ken Gobble

We’re still pretty close to our gas flare limits out there. Of course, the AQMD limitation does not affect our ability to drill. But we would like to have that wrapped up. I believe, in my opinion, the timing looks good right now to have that wrapped up prior to when we plan to start drilling.

Leo Mariani - RBC

Okay. So that would mean it will be wrapped up by the end of the year?

Ken Gobble

Yes. I would expect right now because of some legislation that’s been approved, that will kind of change the way small businesses’ emissions are handled in the state. I would expect that shortly after the first of the year, we would hope to have that wrapped up, Leo.

Leo Mariani - RBC

Okay. On the debt side, Tim, I think you had mentioned paying off additional debt in the short-term. I think you had used the term kind of ‘when due’. Is your credit facility amortized at this point in time or you’re unable to pay that off as you see fit? Or could give me some more color on that?

Tim Larkin

Yes. These borrowings are in tranches, Leo, where we lock in a monthly LIBOR rate or a three-month LIBOR rate. So if you pay it off before the tranche matures, you incur these breakage fees. So, what I was trying to state there was just to reflect the fact that as these individual tranches become due, then that would be logical time to pay them down. But the credit facility is in its – the overall credit facility is due November 2012.

Norman Swanton

There’s no reduction unless we make the reduction. What Tim is saying is that he’s matching the pricing as it comes up with the –

Leo Mariani - RBC

Yes.

Norman Swanton

(inaudible) and that would be a convenient time to make the pay downs. Correct, Tim?

Tim Larkin

Yes.

Norman Swanton

Okay.

Tim Larkin

But the facility itself is not due until the – the borrowings under the facility are not due until November 2012.

Leo Mariani - RBC

Yes, understood, okay. What’s your fourth quarter ‘09 CapEx targeted out here?

Tim Larkin

It’s targeted at 3.5 million.

Leo Mariani - RBC

Okay. You guys have mentioned at this point not having any drilling plan in the Atlantic Rim in 2010, is that – have you had your partner discussions with Anadarko for 2010 or is that just what you folks are thinking at this point of time.

Ken Gobble

No we have held – we pretty well agreed on a 2010 budget.

Leo Mariani - RBC

Okay.

Ken Gobble

With our partners. We’ve held our annual partners meeting and have the budget pretty well in place. Leo, I do expect that there will probably be some flexibility in that if the commodity pricing situation changes.

Leo Mariani - RBC

Yes. Is there a magic number on the gas price where both you and Anadarko would think it would think it makes sense to get out there and start drilling again?

Ken Gobble

I think it’s safe to say right now, we would like to see supply taking care of the issues and see some of this pricing that we’re seeing on the strip price in the rear view mirror before we really start drilling again out there. I think it’s also safe to say from Warren’s perspective it makes a lot more sense to be investing what capital we have to invest now on the oil side.

Leo Mariani - RBC

Sure. So if I may kind of read between the lines there, you’re talking about future strip prices, does that mean you guys want to see more of a $6 type of price in the [front line] here?

Ken Gobble

Honestly, Leo. That project is very profitable in the 5.25 range, realized, but I think once you give – once we see that and see it for a period of time we would be very comfortable in going back to drilling out there.

Leo Mariani - RBC

Okay. I guess jumping back over to Wilmington Townlot. You talked about some of sinusoidals you wanted to do in the Ranger and NWU as well as the Tar locations there and WTU. You said the [EURs] are roughly similar, can you remind us what those [EURs] are on those wells?

Ken Gobble

I would say somewhere in the 175 to 200,000 barrel range.

Operator

(Operator instructions). We have no further questions in the queue, I would like to turn the call back over to Mr. Norman Swanton for closing remarks.

Norman Swanton

I would like to thank you all for joining us today and for your interest in Warren Resources. Thank you and have a 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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