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Executives

Norman Swanton – Chairman and CEO

Timothy Larkin – EVP and CFO

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

Analysts

Leo Mariani – RBC Capital Markets

Philip McPherson – Global Hunter Securities

John Abbott – Pritchard Capital Partners

John Lowe – Sidoti and Company

Warren Resources, Inc. (WRES) Q3 2011 Earnings Call November 8, 2011 10:00 AM ET

Operator

Good day ladies and gentlemen and welcome to the third quarter 2011 Warren Resources Inc Earnings Conference Call. My name is Recenia and I’ll be your operator for today. At this time, all participants are in listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions). As a reminder this conference is being recorded for replay purposes.

I would now like to turn the conference over to our host for today, Mr. Norman Swanton, Chairman and CEO of Warren Resources. Please proceed.

Norman Swanton

Thank you, operator. I apologize for delay this morning, we had some telecom issues. Good morning everyone. Thank you for joining us for Warren Resources third quarter 2011 financial and operating results conference call. We are conducting the conference call this morning from our Long Beach California Executive Office and with me is Steve Heiter, our Executive Vice President and the CEO of our operating subsidiary Warren E&P Inc and Tim Larkin, our Executive Vice President and CFO is joining us from our New York City office.

Before I turn the microphone over to Tim to cover the financial results and Steve to discuss our oil and gas operations, I would like to briefly comment on our overall performance for the third quarter of 2011 and the future direction of the company.

We are well aligned and execute our 2011 capital plan and anticipate drilling 45 gross, 10.3 net producing wells in our in our drilling program with the target of horizontal and sinusoidal wells in California and 25 coalbed methane obligation wells in our 113,000 acre mega-unit in Wyoming. Upon completion of our 2011 drilling program, I believe we should be in good position to confirm the recoverable oil reserves in the Tar, Ranger and Upper Terminal oil zones and possibly the deeper forward 237 Schist zones.

These reservoirs could be the foundation to executive a long-term development drilling program in our two Wilmington units in California. We have also been actively working to update our resource assessment of our Niobrara prospect in Washakie Basin and we are encouraged by our preliminary geological study. We achieve many of our regulatory goals in the third quarter and we believe the prospects for longer-term solutions to the oil industry issues in California will become more favorable.

We are honored to be awarded the 2011 independent Company Chairman’s Stewardship Award from the Interstate Oil & Gas Compact Commission for Warren’s innovative drilling cellars project at the Wilmington Townlot Unit in California and as an example of a company that goes beyond the basic mandates of law and regulation to protect and enhance our nation’s natural resources.

Our liquidity position remained strong. We believe that we have most of the permitting and rig issues behind us and I believe that both our near-term and long-term outlook has never been better.

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

Timothy Larkin

Thanks, Norman. Before I discuss the company’s financial results released earlier today, I would like to remind everyone that all statements made during our conference call that are not statements of historical fact constitute forward-looking statements and are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results could vary materially from those contained in the forward-looking statements. Factors that could cause actual results to differ materially from those in the forward-looking statements are described in our Forms 10-K and 10-Q, other periodic filings with the SEC and our press releases.

As Norman mentioned, we had strong second quarter and we’re excited about the balance in 2011 and beyond. Our cash flow from operations continues to be solid and we’re in a strong liquidity position. As of September 30, 2011 we have $50.5 million available under our senior credit facility. We drilled 10 million during October 2011 and as a result we have paid down a net $35.5 million of debt under this facility over the last two years.

Today we reported net income of $10.2 million for the quarter or $0.14 per diluted share and adjusted net income of $6.2 million or $0.09 per diluted share excluding gains from hedging activities of $4 million. Additionally during the quarter we generated $12.2 million of cash flow from operations. Also, our oil and gas production was 449,000 barrels of oil equivalent for the quarter or 4900 barrels of oil equivalent per day.

Production from our two oil fields in California totaled 232,000 net barrels during the third quarter, a 13% decrease from the 255,000 net barrels produced in the same period of 2010. Additionally, natural gas production primarily from our Atlantic Rim project in Wyoming was strong and overall natural gas production increased 4% to 1.3 net billion cubic feet during the third quarter compared to 1.25 net billion cubic feet during 2010.

The average realized oil price for the third quarter of 2011 was $89 per barrel compared to $69 per barrel during the third quarter of 2010 an increase of 29%. Our average realized gas price for the third quarter was $4.18 per Mcf compared to $3.87 per Mcf in the third quarter of 2010.

Under our current oil purchase and sale contract with Conoco Phillips which expires in July 2012, the company sells its oil at a price of 87% of NYMEX for the first 1,800 barrels of oil produced per day and at the Midway Sunset price plus a $0.85 bonus and a premium for gravity adjustment for the balance of our production. We currently produce approximately 2,600 net barrels of oil per day. Midway Sunset is currently selling at a premium of $20 to NYMEX.

Our third quarter Wilmington blended oil differential from NYMEX pricing was a negative $3 per barrel. Also during the third quarter, we recorded a net gain from derivatives of $4 million which included a realized loss from derivatives of $4.4 million and an unrealized gain from future derivatives of $8.4 million. Among our oil and gas hedges, the company owns a $61.80 NYMEX oil swap for calendar year 2011 at 840 barrels of oil per day or 77,000 total barrels from October 2011 to December 2011.

The company also owns NYMEX FTSE for 1,000 barrels of oil per day or 366,000 total barrels, a strike price $70 per barrel for calendar year 2012. Warren also owns January 2012 oil coal options with a strike price of $110 per barrel for 500,000 total barrels which should partially offset derivative losses on the swap if oil prices increase.

Approximately 50% of our forecasted remaining 2011 natural gas production is costless collars with floor prices between $4.00 and $4.25 per Mcf and ceiling prices at $5 or higher per Mcf. As a result of improved oil prices, oil and gas revenues for the third quarter increased 13% to $26 million compared to 2010.

Total operating expenses increased 11% to $19.2 million during the third quarter of 2011 compared to 2010. Lease operating expenses increased 3% to $7.9 million due to increased California at Warren taxes and increased transportation cost associated with our Wyoming natural gas. Anadarko now sells our gas downstream at a higher price than CIG firm and charges us transportation fee. We expect oil LOEs to average approximately $20 per barrel for the balance 2011.

Depletion, depreciation and amortization expense for the third quarter increased 36% to $7.6 million compared to the third quarter of 2010. DD&A was $16.94 per BOE during the third quarter of 2011 compared to $11.83 per BOE during the third quarter of 2010. This increase in DD&A on a per barrel basis resulted from higher estimated future development costs as of December 31, 2010 compared to 2009. Additionally, DD&A increased due to depreciation expense related to our new drilling rig.

General and administrative expense decreased 8% to $3.7 million during the third quarter of 2011. This decrease resulted from a reduction of $400,000 to our annual incentive compensation accrual recorded during the second quarter of 2011 compared to the same period of 2010. Additionally, both stock option expense and legal expense decreased $200,000 during the quarter. This decrease was offset by an increase in salary expense of $300,000 for the quarter.

Interest expense decreased 16% to $749,000 as we continue to pay down outstanding balance on our credit facility as previously mentioned. Net cash provided by operating activities was $12.2 million during the third quarter of 2011 compared to $16.1 million during the third quarter of 2010.

Our forecast to 2011 capital expenditure budget is $71 million, $60 million related to our California oil fields and $11 million related to our Wyoming natural gas fields. This includes expenditures of approximately $39 million for drilling up to 20 producing wells in our WTU oil field in California, $14 million for related for infrastructure costs in our WTU and NWU oil fields.

Our California capital expenditure budget also includes $7 million for expenditures related to our new drilling rig. Our 3-D seismic shoot of our California properties previously budgeted for 2011 has been rescheduled for the first quarter of 2012. Additionally, we forecasted $10 million for drilling gas wells and $1 million for infrastructure cost related to our Atlantic Rim project in Wyoming. In order to form the Mega-Unit which protects approximately 113,000 gross acres in our Atlantic Rim project, the company has agreed to drill 25 gross and 10 net wells in 2011 and future years. This acreage is perspective for coalbed methane natural gas, Niobrara oil and deeper formations. We do winter stimulations on drilling through July 2012, we plan on commencing our Niobrara activity in the later part of 2012.

Our borrowing based under our credit facility is $120 million. The next redetermination is scheduled for this month due to our strong liquidity position and the lender fees associated with increasing our borrowing base, we did not ask our lenders for a borrowing based increase for our last two redeterminations.

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.

We reported our fourth quarter and full year 2011 production and capital expenditure guidance in our press release disseminated this morning.

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

Stephen Heiter

Thank you, Tim. Now I’d like to update Warren’s operational details. Since commencing drilling operations in April of 2011, Warren has drilled and completed 11 new wells in the WTU consisting of three Upper Terminal wells, two Ranger wells, five Tar wells and one well that penetrated both the Ford and 237 formations.

Thirty day initial production rates for the new Tar wells averaged just over 170 barrels of oil per day. These new Tar wells typically experience a 50% to 60% reduction in producing rates after a few months, which is a normal decline in results in our typical ultimate recoveries of 100 to 150,000 barrels of oil per well.

Drilling and completion problems which have been largely resolved hampered the performance of our Ranger and Upper Terminal wells. The three new Upper Terminal wells averaged about 50 barrels of oil per day initially and have experienced minimal decline to date. Initial production rates for the first new Ranger well with 70 barrels of oil per day and after three months the average rate is 60 barrels of oil per day. Average rate for the second Ranger well is about 95 barrels of oil per day after one week of production.

As we learned from these early sinusoidal Upper Terminal and Ranger wells, we expect improved drilling and completion results which will lead to improved performance. Over the long run, we’d expect these wells to range from 75 to 150 barrels of oil per day, initial rates with ultimate recoveries of 125 to 200,000 barrels of oil. Note that our best Upper Terminal well, WTU 2161 from last year had an initial production rate over 225 barrels of oil per day with an expected ultimate recovery of about 240,000 barrels of oil.

Through the new wells, we drilled potential Tar D1A reserves in a new south block. Third day initial production rate for each of these two wells average nearly 180 barrels of oil per day confirming new reserves. Additional wells have been planned in this fault block where the company currently has no reserves booked.

The new Ford formation well was drilled through the deeper 237 formation in order to obtain modern log data through the deeper zones. Results of the logs justified completing the well in both the 237 and the Ford zones. These two zones will be comingled and placed on production later this week.

Success with Ford well could set up a multiyear water flood development program. The second Ford well is planned for late 2011. Warren’s new drilling rig performed trouble free during the third quarter. As previously mentioned, we had experienced significant startup problems with some of the major rig components. All those components have been repaired or replaced in the comprehensive maintenance program is under development.

We contracted for a second drilling in the WTU in September that will allow us to drill up to 20 wells in 2011. This rig is currently drilling its third well, a Tar extension well to the south.

As previously reported on June 20th, we received approval from the California Division of Oil, Gas and Geothermal Resources to commence water injection into a WTU 2163I our Tar injection well drilling in 2010. Current injection rate is about 5,000 barrels of water per day. As a result of 2163I, we currently have no production shut in at WTU. We have several additional water injection applications pending with the DOGGR and expect approval in the next several months. In addition, we are also preparing a pilot monitoring plan which should improve the likelihood of permit approvals from the DOGGR.

On July 19, 2011, the AQMD certified the company’s CEQA documents and issued all of their related permits including gas handling equipment. These permits allow us to install several pieces of best available controlled technology equipment including a clean enclosed burner, a new heater/treater and gas injection compressor. A clean enclosed burner has been in operation for couple of months and construction of the heater/treater and gas injection compressor is underway.

Upgrades to the production and water handling facilities in the company’s north Wilmington unit are nearing completion. This work will accommodate anticipated increased oil production from NWU when drilling activity is resumed in early 2012. In addition, we are in the process of acquiring a necessary Townlot around our NWU central facility for a second drill site for more than 50 wells in our development plan.

Commencing in July 2011, Warren participated in the drilling of 25 gross or 10.3 net new coalbed methane wells in the 113,000 gross acres Spyglass Hill Unit in the Atlantic Rim area of Wyoming. We will also participate in one new well in the Catalina unit during the fourth quarter of 2011. All 25 Spyglass Hill Unit CBM wells have been drilled and cased and currently 10 wells have been placed on production and are in the de-watering stage.

We continue to evaluate the potential of Warren’s Atlantic Rim acreage for Niobrara oil development. We recently concluded a regional geologic study of the Niobrara and are considering the best options for development.

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

Norman Swanton

Thanks, Steve. Operator, we’ll now take questions.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Leo Mariani from RBC Capital Markets. Please proceed.

Leo Mariani – RBC Capital Markets

Hey, guys. Could you elaborate a little bit on sort of what’s encouraging from your geological study on the Niobrara?

Stephen Heiter

It was a preliminary study Leo, it wasn’t in great depth. But, we had geological firm, take a look at all the wells drilled in the area of our unit and they mapped grid (ph) activities and structure and faulting. And they believe that we have several townships that the possible development locations and need to do a little bit further analysis of the existing 2D and 3D which we’re in the process of doing now. But, it does look encouraging.

Leo Mariani – RBC Capital Markets

Okay. In terms of your well cost, could you just go into a little bit more detail about how much it cost you to drill these Ranger and Upper Terminal wells?

Stephen Heiter

We have drilled anywhere from 4,500 foot wells to 9,500 foot wells depending on the whether it’s a modern well or step-out well. So the costs range anywhere from say 1.5 to 1.9 million with no problems. Now, we’ve drilled a couple of wells that cost a lot more because of the drilling problems but the last four or five wells have gone very well, and they’re now back within the range of where we expect them to be.

Leo Mariani – RBC Capital Markets

Okay. And how about that new well you drill to the Ford. How much was that?

Stephen Heiter

That was in that same range. We drilled deeper than we planned because we had some positive logs and then we plugged back and so it cost a little bit more. It was a very simple well to drill. It was 14 days to TD. And so it would probably be about that same range maybe but the cost will be a little less because of no gravel packing. So probably 1.5 with the full development depending on the directional work.

Leo Mariani – RBC Capital Markets

Okay. And Tim, I think you talked about your contracted Conoco Phillips rolling off the middle of next year where you’re definitely getting pretty sizable discounts in NYMEX and a large percentage of your oil production there. Guys negotiating with them for a new contract and maybe looking to somebody else to give you little better deal there on oil?

Norman Swanton

This is Norman. Yes, we are examining a lot of different alternative to maximize realization prices in California and they are going quite well.

Leo Mariani – RBC Capital Markets

All right. And I guess water injection permits I guess you guys are still hoping for some in next several months. I think you made up commenting your press release that the regulatory wheels are turning a little bit slower than expected. You guys anticipate any effects on your 2012 program at this point?

Norman Swanton

No, if anything I see an improvement in the future and the issue for the DOGGR permits.

Leo Mariani – RBC Capital Markets

All right. Thanks guys.

Stephen Heiter

Thanks Leo.

Operator

Your next question comes from the line of Phil McPherson with Global Hunter Securities. Please proceed.

Philip McPherson – Global Hunter Securities

Hi, good morning guys.

Stephen Heiter

Good morning.

Norman Swanton

Good morning, Phil.

Philip McPherson – Global Hunter Securities

Great job on the quarter on the cost side. I was curious for 2012 with the two rigs running one in each unit, how many wells you think you could get down under that scenario?

Stephen Heiter

With normal performance Phil, we could drill two wells a month approximately. But, we’re going to take a look at our performance for this year, where we want to drill next year at the WTU and so I don’t know yet how many wells we’re going to drill next year total. But, a lot of it hinges not only on the performance of the wells but also as we mentioned the water injection permits which we – we would certainly think are going to get a lot better ending the changes at the top of DOG. But, that’s yet to be seen. But, in long run we think that’s got – it has to improve. I don’t think there is any question about that.

But, in a short-term it might affect us in the next few months until they get their organization straightened up. But, we could drill in a range of 10 wells at NWU let’s say producers and injectors and then take a look at what we’ve got. But, at WTU we could just keep drilling depending on performance.

Philip McPherson – Global Hunter Securities

And two wells per month, is that per rig or one per rig?

Stephen Heiter

Two per rig if things well. Two weeks per 14 to let’s say 20 days per well in that range. So, almost two wells a month.

Philip McPherson – Global Hunter Securities

Got you.

Stephen Heiter

Per rig.

Philip McPherson – Global Hunter Securities

And your current permits that you have at WTU, you have enough capacity now to inject water to keep the rig running without having a slowdown?

Stephen Heiter

We’re going need additional water injection permits over the next few months, if we continue drilling at WTU. Right now, we have no product shut in and we have additional – a little bit additional injection capacity. We are going to need more wells over the next few months to keep going.

Philip McPherson – Global Hunter Securities

Can we – can you quantify like you need like one injection permit per quarter is there per number of wells that you envision like every wells you need a permit. How do we think about it?

Stephen Heiter

If we are drilling UT and Ranger wells, those – particularly UT wells make a lot more water. So, it depends on our mix of production. But, I would think we would need probably at least one a quarter.

Philip McPherson – Global Hunter Securities

Okay. At WTU.

Stephen Heiter

Ranger.

Philip McPherson – Global Hunter Securities

Okay. And then, how about at NWU?

Stephen Heiter

Probably, two or three for the year.

Philip McPherson – Global Hunter Securities

Great. And next year, how much CapEx do you think you need to spend on infrastructure. I know you spend I think it was $8 or $10 million maybe $7 million this year or maybe you could review what you spent in 2011 on infrastructure and what you think you need to spend on 2012?

Timothy Larkin

Phil, this is Tim. We budgeted – we spent according to our plans $7 million in – for facilities in the WTU and also $7 million for facilities in the NWU.

Philip McPherson – Global Hunter Securities

Okay, great. And how is that set you up for 2012?

Timothy Larkin

Steve, do you want to maybe.

Stephen Heiter

Well, I don’t have the numbers in front of me Phil but we’re going to be almost finished – probably finishing up mid first quarter at NWU getting that site ready to drill. I don’t know how many expenditure it’s going to carry over the first quarter, most of its going to be done this year. But, we will have some in the first quarter and that will be the bulk of it for the year. We’ll be ready to complete the drilling, start the drilling at the end of the first quarter or mid quarter and WTU, it will mostly be gas injection or gas sales depending on which way we decide to go with that and that will be the majority of our capital expenditures over the next year at WTU.

Philip McPherson – Global Hunter Securities

And where do you put that number yet. Is that like another $7 million or…?

Stephen Heiter

Yeah, just the gas sales could be 4 million. So, between 4 and 7 or 8 in that range probably.

Philip McPherson – Global Hunter Securities

That’s helpful. And it sounds like given current natural gas price environment that this run rate of kind of at 10 or $11 million a year is probably just a norm for a while until you get an uplift in gas or something changes up there. Is that a good number to use for 2012?

Timothy Larkin

It is, yes.

Philip McPherson – Global Hunter Securities

Okay, great. Well, thanks guys. I appreciate keep up the good work and good luck getting the permits.

Stephen Heiter

Thanks.

Timothy Larkin

Thanks, Phil.

Operator

The next question comes from the line of John Abbott from Pritchard Capital Partners. Please proceed.

John Abbott – Pritchard Capital Partners

Good morning.

Timothy Larkin

Good morning, John.

Norman Swanton

Good morning, John.

John Abbott – Pritchard Capital Partners

Yeah, Just quickly here. Could you remind me how many potential locations you have – you think you have with sinusoidal drilling in the Tar, the Ranger and then Upper Terminal broken out?

Stephen Heiter

I don’t have those numbers in front of me. But, it’s – are you talking about total? Total is about…

John Abbott – Pritchard Capital Partners

You had – it looks like you’re having pretty good success here with the Tar formation. Ranger and Upper Terminal there is – those rates could improve over time. But, just out of curiosity I was looking just at the Tar, how many potential locations you think you have for that?

Stephen Heiter

We have picked up a few this year since our drilling has been so successful. So, I would say we still have in the range of 20 to 25 which is kind of what we’ve been saying for the last few years. But, we’ve been finding more locations as we drill. So, that could change but right now we’re thinking at least 20 to 25.

John Abbott – Pritchard Capital Partners

All right. And then, when you get down to the Ranger and Upper Terminal, are there more locations with those areas?

Stephen Heiter

The problem is we had a total development inventory at the end of this year in the range of 200 wells and so if you take 20 or 25 off that, that leaves about 180 split between the Ranger and the Upper Terminal and I don’t remember the split.

John Abbott – Pritchard Capital Partners

All right. And then, my second question here, okay, it looks like they let go the supervisor for the DOGGR. Any thoughts on the replaced there or what are you hearing out of that?

Stephen Heiter

We haven’t heard about any potential replacement. Yeah, it was the head of the DOG and then her boss as well the head of the – acting head of the department of conservation and as everybody knows there was a log jam with the water injection permits and we got one of the very, very few over the last two years that was approved and so I don’t – it can’t certainly can’t get any worse. It has to get a lot better because the industry can’t be hampered like that on water injection permit. So, I believe that we’ll probably be in the short-term, there is probably going to be a continued road block. I don’t know how long that’s going to be, whether it’s a week or two weeks or a month. But in a long-term it has to get significantly better both for the time it takes to get water injection permits and drilling permits and other permits that continue conducting our business.

John Abbott – Pritchard Capital Partners

All right. I appreciate. Thank you.

Stephen Heiter

Thank you.

Norman Swanton

Thanks, John.

Operator

(Operator Instructions). And the next question comes from the line of John Lowe from Sidoti and Company. Please proceed.

John Lowe – Sidoti and Company

Hey guys, this is J.B. How you’re doing?

Norman Swanton

Hey, J.B.

John Lowe – Sidoti and Company

Thanks for the color on the permitting things. Real quick, you guys mentioned there is a pilot monitoring plan. Can you guys kind of go into detail about – what that’s all about?

Stephen Heiter

It’s a long kind of a technical story. But, in order to get injection well approved you have to look at all the older abandoned wells within the quarter mile and some of those wells were drilled in the 30s and 40s and 50s and obviously not up to today’s standards. And so, if you have some of those bad wells within your – within a quarter mile, you’re not going to get an injection well approved. Now, the way to get resolve that issue, one way to resolve that issue other than abandoning wells that you can’t get to is to install monitoring wells that actually monitor where the water is going both by pressure and perhaps by sampling and that will forecast whether or not you have any future problems with these old improperly abandoned wells and it’s a pretty standard methodology throughout the U.S. It just hasn’t been done for this purpose in California. And so, we’re preparing a plan for a pilot monitoring for one of our current injection applications and we’ll be ready to submit that shortly.

John Lowe – Sidoti and Company

Okay, great. And does that cost less than 1 million or it’s not much to cost to drill I think.

Stephen Heiter

No, not for the pilot because we’re going to use an existing well to convert as a monitoring well and we are working with couple of local companies that do this for the city of LA. They have like 50 monitoring wells throughout the LA basin monitoring for water usage, freshwater usage and so they do this for living and we’ve been working very closely with them on preparing our plan and exactly how to do it and what to expect.

John Lowe – Sidoti and Company

Okay, great. Thanks. And real quick, remind me which formation over NWU you guys are going to be targeting, is it the Ranger?

Stephen Heiter

Yes, that’s correct.

John Lowe – Sidoti and Company

Okay. And then, lastly what are you kind of expectations for the Ford completion that’s going to come on in the next week or so?

Stephen Heiter

Well, we don’t know. We were – no, we ran electric logs, modern electric logs which we didn’t have and we had a mud log and we had shows and that doesn’t mean anything other than it’s encouraging. Quantitatively that’s a main thing. Qualitatively it does and so, we are anxious to find out.

John Lowe – Sidoti and Company

All right. I am too. Thanks very much. Go ahead.

Stephen Heiter

Thanks J.B.

Timothy Larkin

Thanks.

Operator

I would now like to turn the conference over to Mr. 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

Ladies and gentlemen, that concludes today’s conference. Thank you for your participation. You may now disconnect and have a great day.

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