Warren Resources, Inc. Q2 2010 Earnings Call Transcript

Aug. 4.10 | About: Warren Resources, (WRES)

Warren Resources, Inc. (NASDAQ:WRES)

Q2 2010 Earnings Call

August 04, 2010 10:00 a.m. ET

Executives

Norman Swanton - President & CEO

Tim Larkin - EVP & CFO

Ken Gobble - President & COO

Analysts

Leo Mariani - RBC Capital Markets

Walter Morris - Barbow Growth

Joel Musante - C.K. Cooper

Operator

Good day ladies and gentlemen and welcome to the Second Quarter 2010 Warren Resources Inc. Earnings Conference Call. My name is Yvette and I will be your operator for today, (Operator Instructions).

I would now like to turn the call over to Mr. Norman Swanton, Chairman & CEO of Warren Resources. Please proceed sir.

Norman Swanton

Thank you, welcome ladies and gentlemen to Warren Resources, second quarter 2010 financial and operating results conference call. I'm pleased to be here with Tim Larkin, our Executive Vice President, CFO and Kenneth Gobble, our COO and President Warren E&P is also joining us to disuse our operating results.

Before I turn the microphone over to Tim, to cove the financial results and Ken, to discuss our operating results I would like to briefly review some second quarter 2010 highlights.

During the second quarter of 2010, oil and gas production hit a record 2.6 Bcfe and revenue increased 38% to 21 million compared to the second quarter of 2009. Our net earnings per share were 8.6 million for the quarter or $0.12 per diluted share. Compared to a net loss of 9.2 million for the second quarter of 2009 or $0.16 per diluted share, representing a $0.28 per share positive swing in earnings.

I'm very pleased that we resumed drilling during the second quarter in out California Wilmington Townlot Unit, or WTU and completed our seventh new Tar formation well. The seven new tar wells are currently averaging 99 barrels of oil per day or 695 barrels of oil per day in the aggregate.

In early July, we also filled our first J sand sinusoidal Upper Terminal well in the WTU, which had initial production of approximately 225 barrels per day and it's currently producing at a rate of 180 barrels of oil per day.

We competed our second sinusoidal Upper Terminal well in the HX sand last week and the preliminary results are encouraging. Although our sinusoidal upward terminal drilling program is in the concept phase, our California geological staff has identified 60 to 80 potential sinusoidal Upper Terminal producer well locations in the WTU.

Based on these strong drilling and production results, we have increased our 2010 capital expenditure program by 7.5 million and we'll be accelerating our drilling in Wilmington. We are planning to drill an additional four WTU wells during the fourth quarter of 2010, including two additional Upper Terminal sinusoidal wells, one more tar formation well and out WTU sinusoidal ranger formation well.

Suddenly, even though we have not drilled any new wells in 2010 in our Atlantic Rim coalbed methane project in Wyoming, our frac program and well optimization increased our natural gas production by 25% to a record 1.2 billion cubic feet of cash equivalent compared to 0.9 Bcf in the second quarter 2009. We believe we are now fully back on track. To demonstrate a huge potential untapped -- or this huge untapped potential of our reserves in the Wilmington Field units in California.

The natural gas reserves and the large Atlantic rim Coalbed Methane Project in Wyoming and then emerging perspective Niobrara play below of the base of the Mesa Verde in the Atlantic Rim project. As I have stated repeatedly, I believe the strong operating results such as those achieved in the second quarter of 2010, are the true driver of future shareholders value it is through sales results that we were attract, interest from the investment community.

I continue to believe that our long-term outlook has never been better. We will continue to build environmentally sound foundation to deliver strong growth in domestic production, reserves and profitability for the years ahead in all of 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 discussed the company's second quarter 2010 financial results release earlier today, I'd 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 Form 10-K and 10-Q, other periodic filings of the SEC and our press releases.

During the second quarter, our cash flow from operations continue to improve our balance sheet and liquidity position, also as Norman mentioned, we placed seven oil wells and Upper Terminal Sinusoidal Well on production since we re-commenced our drilling program in April this year.

Results have been encouraging. As of June 30, 2010, current asset succeeded current liabilities by more than $7 million and after paying down another $2.5 million of debt during the second quarter, we now have $37.5 million available under our senior credit facility. We've now paid down $32.5 million of debt during the last nine months. Actually, even though we're increasing our capital expenditure budget, primarily to drill six additional wells in California and to require additional working interest in our Atlantic Rim project, we expect to fully fund our 2010 capital expenditures with cash flow from operations.

We get a very good second quarter, reported a net income of $8.6 million for the quarter or $0.12 per diluted share. Additionally, during the quarter, we generated $9.7 million of cash flow from operations; also we increased our own gas production to a record 2.6 Bcfe or 29 million cubic feet a day for the quarter.

Production from our two oil fields in California totaled 241,000 barrels during the second quarter, 2% increase from the 237,000 barrels produced during the second quarter of 2009. Additionally, natural gas production from our Atlantic Rim project was strong in overall natural gas production increased 25% to 1.2 billion cubic feet during the second quarter compared to 913 million cubic feet during the same period of 2009.

The average realized oil price for the second quarter of 2010 was $70 per barrel compared to $54 per barrel during the second quarter of 2009, an increase of 30%. Our second quarter Wilmington oil differentials for NYMEX prices were approximately $8 per barrel. Also during the second quarter, we had a realized loss from hedging activities of 800,000 and an unrealized non-cash gain from future hedges of $5.2 billion.

During the quarter, when the price of front month NYMEX contract for oil was in the low 70s per barrel, the company repurchased 31% of its 2011 oil swap for $2 million. Our 2011 oil swap has a contract price of $61.80 per barrel. This reduced our 2011 swap from 1,225 barrels oil per day to 840 barrels of oil per day or a reduction of approximately 141,000 total barrels.

Our average realized gas price for the second quarter was $3.62 per Mcf compared to $2.67 per Mcf in the second quarter 2009. As a result of increased production and improved commodity prices, oil and gas revenues for the second quarter increased 38% to $21 million compared to 2009.

Total operating expenses increased 19% to $16 million during the second quarter of 2010 compared to 2009. Lease operating expense increased 25% to $6.7 million due to increase in maintenance and plugging and abandonment projects in California. We expect LOEs to average approximately $18.50 per net barrel in 2010.

DD&A for the second quarter decreased 1% to $5.1 million compared to second quarter 2009. DD&A was $1.97 per Mcfe during the second quarter of 2010 compared to $2.21 per Mcfe during the second quarter of 2009. This decrease in DD&A on a per Mcfe basis resulted from a lower estimated future development costs as of June 30, 2010 compared to 2009.

General and administrative expense increase 47% to $4.2 million during the second quarter of 2010. This increase resulted from recording a 1 million incentive compensation accrual relating to our 2010 year-end incentive compensation plan and additional stock option expense of $300,000 compared to 2009. In total, we recorded non-cash stock option expense of $756,000 during the second quarter of 2010. Interest expense decreased 41% to $881,000 as we continued to pay down our outstanding balance on our credit facility as previously mentioned.

Net cash provided by operating activities was $9.7 million during the second quarter of 2010 compared to $8.5 million during the second quarter of 2009. We have increased our forecasted 2010 capital budget from $30 million to $37.5 million. This includes expenditures of $30 million for our oil fields in California and $7.5 million for our Atlantic Rim natural gas project in Wyoming. Budget includes an increase in the number of wells to be drilled in California from eight wells to 14 wells.

Additional this includes purchasing additional working interest in Doty Mountain and Catalina units in our Atlantic Rim project for $1.8 million. As I previously mentioned we expect to fund our 2010 capital expenditure budget with cash flow from operations.

Our borrowing base is a $120 million. The next re-determination is scheduled to be completed in October 2010.

Currently Warren has availability of $37.5 million under its 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.

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. As the operator of the WTU and NWU oil assets in California and co-joint venture of the Atlantic Rim project with Anadarko, the company has the ability to modify its capital expenditure budget as commodity and financial markets change. With second quarter and full year 2010 production and capital expenditure guidance in our press release earlier today.

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

Ken Gobble

Thanks Tim. Warren has now placed seven the tar wells on production as part of the 2010 WTU development program four of these wells were included in the company's proved undeveloped reserve base.

Two of the new wells were drilled to test potential Tar D1-A sand to the north of the current producing area. The seventh new well was drilled on the western flank of the existing development. Initial results of the new well drilled to the north has been encouraging. We intend to continue to evaluate this production in order to determine the potential to drill additional wells in this area in the near future.

Warren was able to significantly improve the drilling and completion efficiency in he 2010 program which has resulted in reducing the drilling time from an average of 17 days per well for 2008 program to 11 days average for the 2010 program.

The Long Beach staff has done an excellent job in all phases from planning to executing the company's 2010 Wilmington development program. The Company has also drilled the first two sinusoidal horizontal wells targeting remaining reserves in the upper terminal formation in WTU.

The first of these two wells was placed on production at third week of June. This well targeted the J sand portion of the upper terminal formation. After seeing six weeks of production data from this well the results have also been encouraging.

The second sinusoidal well targeted the HX section of the upper terminal and was just recently placed on production. This well continues to clean and conclusive results are not yet available.

Warren intends to drill one additional sinusoidal horizontal well on to the ranger formation later in 2010. These wells represent the company's first step in evaluating the viability of combining our three dimensional geological modeling with sinusoidal horizontal drilling technology to further exploit results in the upper terminal formation.

Production from the company's Atlantic Rim project continues to grow as a result of fracture stimulations of existing wells in both the Sun Dog and Doty Mountain units. Warren and its partners in the project are planning to stimulate an additional 36 wells in the second half of 2010.

We are also planning to drill and complete a deep injection well in the Sun Dog unit to increase water injection capacity later in the year. The company expects to resume drilling in the Atlantic Rim 2011.

Thank you and now I'd like to turn the call back over to Norman.

Norman Swanton

Thank you Ken, operator we'll now take questions.

Question-and-Answer Session

Operator

(Operator Instructions), your first question comes from the line of Leo Mariani with RBC Capital Markets. Please proceed sir.

Leo Mariani - RBC Capital Markets

Hi, good morning guys. What is your current cash balance at kind of June 30 here?

Tim Larkin

Our cash balance was 15.3 million Leo.

Leo Mariani - RBC Capital Markets

Okay. I guess you talked about dropping your drilling days at WCU to 11 days. What does that do to your well cost at WCU? What have those averaged so far this year?

Tim Larkin

They were originally budgeted at approximately 1.5 to 1.6 million and we're drilling them in about 1.2 -- at 1.2 million.

Leo Mariani - RBC Capital Markets

Okay. And in terms of drilling the sinusoidal wells, I guess you guys had a couple that you did in the quarter there at the other zone you drilled there. What did those cost - upper terminal sinusoidal?

Tim Larkin

We'll first do a right around 1.7, the last one is just recently completed, both of them came in late in the program so we don't have all of our cost in, Leo, but that's probably a pretty good estimate.

Leo Mariani - RBC Capital Markets

Okay. Would you expect the Ranger well to be similar in the costs then?

Tim Larkin

We would, most of those are a little bit long to reach, but they're all going to come in there right around that number, we would expect.

Leo Mariani - RBC Capital Markets

Okay. I guess it looks like that first upper terminal well is holding up pretty nicely. Do you guys have any kind of initial estimated EUR on that?

Tim Larkin

We're probably somewhere in the neighborhood of 225 - 250,000.

Leo Mariani - RBC Capital Markets

Okay.

Tim Larkin

But you know it's a little early to say conclusively, but that's were we're at right now on that well.

Leo Mariani - RBC Capital Markets

Okay. And how about in the Tar wells that you drilled this year? Any estimated EUR there?

Tim Larkin

You know I'd throw your range out there probably between 125 and 175, on the seven wells.

Leo Mariani - RBC Capital Markets

All right. You guys talked about a -- on the number side of things, a $1 million accrual during the quarter. Was that a cash accrual in your G&A?

Tim Larkin

It's was a non-cash accrual.

Leo Mariani - RBC Capital Markets

Okay. And just that's related to what you would expect to pay out for the 2010 incentive comp program. Is that right?

Tim Larkin

Correct.

Leo Mariani - RBC Capital Markets

Okay. I guess, jumping over to the Niobrara real quick, what gives you folks confidence that there may be some potential for that on your acreage as you guys as fairly far away from sort of the traditional fairway in the DJ Basin where everyone is drilling right now?

Tim Larkin

Well, one of the best vertical wells in the state of Wyoming is sitting about a mile off our lease position.

Leo Mariani - RBC Capital Markets

Okay. And how much well control do you guys have around there? Is there--are there multiple other penetrations that have produced in the Niobrara?

Tim Larkin

Actually, across our whole lease position are very few penetrations and even fewer longs. Probably on -- across our project area as you know which is quiet large, 175,000 acres, not that we control, but if you look at the whole outline of the area, there's only about 50 penetrations. One other thing that we find very encouraging is the whole lease position is centered in the oil window there.

Leo Mariani - RBC Capital Markets

Okay. Thanks, guys.

Norman Swanton

Thanks Leo.

Tim Larkin

Thanks Leo.

Operator

Your next question comes from the line of Walter Morris with Barbow Growth. Please proceed, sir.

Walter Morris - Barbow Growth

All right, good morning, gentlemen. Good quarter. Congratulations.

Norman Swanton

Thank you, Walter.

Tim Larkin

Thanks Walter

Walter Morris - Barbow Growth

All right, on the Niobrara, you indicate in your press release that you do plan to drill a well sometime in 2011, can you be somewhat more definitive on when that well might go down?

Ken Gobble

Yeah, we really haven't started looking at our 2011 drilling plan in great detail yet but I would say that it's safe to assume it would be sometime towards fourth quarter.

Walter Morris - Barbow Growth

Okay. And can you give us the production data on the well you referred to as a mile from your acreage and who drilled it?

Ken Gobble

No, it was drilled in the early 80s, like Tom Vessel was sitting on the Sierra Madre structure. The well's done about 340,000 barrels I believe it's still doing 35 to 40 barrels a day. No Walter.

Walter Morris - Barbow Growth

300,000-plus barrels, huh. And what's the depth on that, ballpark?

Ken Gobble

5,500.

Walter Morris - Barbow Growth

Okay. And your preliminary work indicates you may have as many as 80,000 net acres prospective for the Niobrara on your acreage?

Ken Gobble

I believe we have 80,000 net acreage that we would have right to develop the Niobrara on as well.

Walter Morris - Barbow Growth

Okay. And then, your guidance for the third quarter of 245 to 255,000 barrels. Considering that you produced 241,000 barrels and net barrels in the second quarter and you brought on a number of highly productive wells, that guidance seems conservative to me. Comment?

Tim Larkin

Our guidance is our guidance. We're increasing production, Walter, and the Company is -- that's our current estimate.

Norman Swanton

Also on the timing of the drilling of the additional wells, would be laid in the year. The rig will be sitting, we don't have a crew so we will be able to get the crew and to finish off those additional well until late in the fourth quarter and the impact from the production standpoint will then be in the first quarter next year.

Walter Morris - Barbow Growth

I understand that but you didn't start drilling until April of this year, did you?

Norman Swanton

That's right.

Walter Morris - Barbow Growth

And you've since completed as we moved through the second quarter and early in the third quarter eight wells plus another one that's just coming on?

Ken Gobble

Well, Walter, you have to remember we did get the benefit of the high IP production from the Tar wells as expected and as we disclosed those wells are currently producing 99 barrels today on average which is excellent but --

Walter Morris - Barbow Growth

Right --

Ken Gobble

Second quarter did get the benefit of the flush IP production.

Tim Larkin

And they do decline relatively quickly in that first year, Walter.

Walter Morris - Barbow Growth

Right. Okay. What is the estimated or projected IRRs on your acquisition of interest in Wyoming? You invested 1.8 million. What kind of returns do you project out of that?

Ken Gobble

Actually, we're forecasting somewhere in the neighborhood of 35-40% there. That was done at a very attractive valuation.

Walter Morris - Barbow Growth

And what gas price did you use in your assumption?

Ken Gobble

550 NYMEX I believe is where we ran that.

Walter Morris - Barbow Growth

And are you going to -- or have you already hedged that out?

Ken Gobble

No. We've got about half of our production hedge right now of our gas production.

Walter Morris - Barbow Growth

Okay. And your capital budget, does that assume the current drilling price of 1.2 million for the Tar wells?

Tim Larkin

Yes. It does.

Walter Morris - Barbow Growth

Okay. Well, congratulations. You've done a great job on efficiencies and bringing your drilling costs down. And obviously, with the kind of EURs you're getting, I mean, it looks like finding costs are substantially below $10 a barrel. On both Tar wells and sinusoidals your returns are very, very high at current oil prices.

Tim Larkin

Yes.

Walter Morris - Barbow Growth

Okay. Congratulations, gentlemen. Great quarter.

Norman Swanton

Thank you, Walter.

Tim Larkin

You are welcome, Walter.

Operator

(Operator Instructions) You have a question from the line of Joel Musante with C.K. Cooper. Please proceed sir.

Joel Musante - C.K. Cooper

Hi. How are you doing, guys?

Tim Larkin

Hi. Joel.

Joel Musante - C.K. Cooper

Yeah. I just had one quick question on your sinusoidal wells. It looks like the most recent one you have results on was much better than what I remember your results were for the Ranger sinusoidal wells in the Ranger formation. Can you just discuss how that -- how those wells differ and why you might have gotten better results in the upper terminal?

Ken Gobble

Well, Joel, the wells we drilled in 2008, in the upper terminal and the Ranger were not sinusoidal.

Joel Musante - C.K. Cooper

Oh, okay.

Tim Larkin

Well, I think he is referring to the Ranger we drilled in NWU.

Joel Musante - C.K. Cooper

Okay.

Tim Larkin

I would expect.

Joel Musante - C.K. Cooper

Right, right.

Norman Swanton

Just to clarify, we did drill a small sinusoidal program in the NWU and those wells have been quite successful but not as attractive as this first upper terminal well that we drilled in. There are a lot of differences between the zones front up, number one. But number two, we have the -- in the WTU we have the added value of all of the new drilling data that we have from buy spot patterns in the upper terminal, which the Long Beach staff was able to incorporate into their 3D geological model, which really pointed out, highlighted once that model was completed, highlighted where the remaining oil saturation was sitting in that upper terminal zone. And they've taken that data and now are targeting those areas where we still have high amounts -- large amounts of oil left in place from the new well data that we have from the buy spot pattern. And they are targeting that with sinusoidal and that's really the primary difference.

Joel Musante - C.K. Cooper

Okay. So you -- so those 60 to 80 locations you were able to identify, you feel pretty confident you can put wells?

Ken Gobble

I think it's important that we keep this in perspective that we've only drilled two wells to-date. Our staff is out there, one of our team leaders is out there and the Long Beach office likes to use the phrase, "drill and learn, drill and learn."

And that's the way we'll go at developing this upper terminal now. I think to forecast the results there out of 60 or 70 locations at this point. It is bit pre-mature but we do know that there is a large amount of remaining oil left in that upper terminal and I think this is the first step of determining the effectiveness of this development strategy.

Joel Musante - C.K. Cooper & Co

Okay. Well, I appreciate it. Thanks

Tim Larkin

Thanks Joel.

Norman Swanton

Thank you.

Operator

You have a follow-up question from the line of Walter Morris with Barbow Growth. Please proceed, sir.

Walter Morris - Barbow Growth

Yes, gentlemen. You indicated you plan to resume drilling in the Atlantic Rim next year. With gas prices at current levels, how do the economics square up for additional drilling there?

Norman Swanton

They are in the high 20s at the current strip price.

Ken Gobble

I would throw this out there, as there will be the way the federal units were set up they allow you to use the previous wells that you have drilled to hold those units in place and we are required to drill five wells in Sun Dog, Doty and Catalina. There is no additional drilling there because of the number of wells we have drilled in the past. There is no additional drilling obligations there for several years but we do have a very large leasehold outside of those units that we would like to maintain and that's going to cost some minimal amount of drilling on it's own and then of course we have some correlative rights issues with the large levels of production that we are seeing where we believe we need to maintain our interest, protect our interest from a drainage perspective.

Walter Morris - Barbow Growth

I see. So it's primarily defensive in nature to protect your position out there because presumably with oil at 80, your returns out of Wilmington, are much, much higher than.

Ken Gobble

There is no question and I believe that you can see kind of the balance on the oil to gas investment that we make in 2010 and I would suspect that it will be similar moving forward as long as you have that large differential margin and return.

Walter Morris - Barbow Growth

Right. Anything more on a Ford test later this year?

Ken Gobble

And we believe there is no question that the gas to oil ratio on the Ford is much different than the upper terminal or even the tar or the ranger. And we really do need to get our regulatory issues with the AQMD conclusively completed before we feel comfortable testing the Ford.

Walter Morris - Barbow Growth

Have you heard any more feedback from success with Oxy or other operators in the Ford formation?

Ken Gobble

It's not something the bulk of the Ford potential is centered around the WTU area. Some of it is outside that unit but marginally so and other offset operators focus have been in the other zones traditionally recently.

So, Ford activity there but I think it's primarily due to what is left in place across the entire structure.

Walter Morris - Barbow Growth

Okay. And then, without additional permit approvals, what drilling capability do you have going forward?

Ken Gobble

We see – I guess you are referring to the gas issue?

Walter Morris - Barbow Growth

Yes.

Ken Gobble

We see a significant amount of gas early from the tar wells and the wells, the tar wells are located near the top of the structure, it appear to have slightly higher gas to oil ratio as you would suspect. Very little gas contribution from additional upper terminal drilling. So as we see these come on, we see our gas kind of come up and spike and then start to drop off rapidly. We expect to have that, we work on that issue everyday. I believe we're getting near completion of a satisfactory finding on the sequel and we would feel very comfortable to get that completed as quickly as possible but I believe we still have the opportunity to continue to drill along the same pace that we're seeing now without much of an issue.

Walter Morris - Barbow Growth

So you're comfortable that well into 2011 you can continue at this current pace even without gas permit relief?

Ken Gobble

I would say that it's possible; that it could be possible if that would be done yes. But we do hope to have that issue resolved prior.

Walter Morris - Barbow Growth

And as I remember, the permit board had sent out the gas permit request for a second evaluation. Is that true? And if so, has that come back with favorable reviews?

Ken Gobble

Well it was put out to public comment. The AQMD is responding to those comments. I think that process has been a circular revision process for quite some time now and we believe that we're nearing completion.

Walter Morris - Barbow Growth

Okay. Good luck. Thank you, gentlemen.

Operator

We have a follow-up question from the line of Leo Mariani with RBC Capital. Please proceed, sir.

Leo Mariani - RBC Capital Markets

Yeah. What is your current gas production in WTU and remind us of what that flare limit is?

Ken Gobble

I don't want to confuse anyone but keep in mind we are consuming a good portion of the gas we're producing on a lease well between our production equipment and the micro turbines that we have sitting there and then we're flaring the balance and our current production is probably somewhere around in between, on a daily basis 200, 220. We're able to flare just under 100 Mcf a day on the flare.

Leo Mariani - RBC Capital Markets

Okay. So, how much are you flaring now?

Ken Gobble

We're probably in the neighborhood of 80 but keep in mind, like you say, every new well that we bring on, it tends to spike a little a bit and then come down rapidly and typically in a matter of a week or two weeks you're back down in that 75 - 80. We've been well under the flair limit but it is and continues to be an issue until we have the final approval from the AQMD.

Leo Mariani - RBC Capital Markets

Okay. And what motivated your acquisition from SM Energy in the Atlantic Rim?

Ken Gobble

Well, two things really. There is no question that we very much like the production and the cost structure there. Even at very low prices it's continued to be profitable. The Doty Mountain unit has just grown tremendously over the last 18 months since we started facture stimulating up there and of course valuation had a lot to do with it.

Leo Mariani - RBC Capital Markets

Okay, thanks.

Tim Larkin

Thank you.

Operator

With no further questions in the queue, I would now like to turn the call back over to Mr. Norman Swanton for closing remarks. You may proceed, sir.

Norman Swanton

I would like to thank you all for your 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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