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Enerplus Corporation (NYSE:ERF)

Q4 2012 Earnings Call

February 22, 2013 11:00 am ET

Executives

Jo-Anne M. Caza – Vice President-Corporate and Investor Relations

Gordon J. Kerr – President and Chief Executive Officer

Ian C. Dundas – Executive Vice President and Chief Operating Officer

Analysts

Greg Pardy – RBC Capital Markets

Kyle Preston – National Bank Financial

Roger Serin – TD Securities

Operator

Good morning. My name is Rob, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus Corporation’s 2012 Year-End Results and Reserves Conference Call. All lines have been placed on mute to prevent any background noise. After your presenters’ remarks, there will be a question-and-answer session. (Operator Instructions) Thank you. Mr. Jo-Anne Caza, Vice President of Corporate and Investor Relations, you may begin your conference.

Jo-Anne M. Caza

Thank you, operator, and good morning, everyone. Thanks for calling in. Gord Kerr, our President and CEO will summarize our fourth quarter and year-end results for 2012 including reserves this morning and Ian Dundas, Executive Vice President and Chief Operating Officer will provide some additional color on our operating results for the year. To answer some of your questions at the end of the call, we also have with us Rob Waters, our Senior Vice President and Chief Financial Officer; Ray Daniels, our Senior Vice President of Operations; Eric Le Dain, our Senior Vice President of Strategic Planning, Reserves and Marketing; and Rod Gray, our Vice President of Finance.

Before we get started, please note that this call will contain forward-looking information. Listeners should understand the risks and limitations of this type of information and review our advisory on forward-looking information found at the end of our news release issued this morning and included within our MD&A and financial statements filed on SEDAR and EDGAR, and available on our website at enerplus.com.

Our financial statements were also prepared in accordance with International Financial Reporting Standards. All financial figures referenced during the call are in Canadian dollars, unless otherwise specified, and all conversions of natural gas to barrels of oil equivalents are done on a 6-to-1 energy equivalent conversion ratio, which does not represent the current value equivalent.

Following our review, we'll open up the phone lines and answer any questions you may have and we'll also have a replay of this call available later today on our website.

With that, over to you Gord.

Gordon J. Kerr

Well, thanks for joining us this morning. I trust everyone, that you’ve had a chance to review our news release that was put out before open of markets. So first of all, looking at the fourth quarter results, I think it’s safe to say that we beat the consensus of analysts on virtually all metrics. Our production was up 5% over the third quarter and our operating G&A costs were down significantly. And most importantly, funds flow grew by almost 50% quarter-over-quarter. These results helped us achieve our revised full-year targets as well. And we delivered on our annual production guidance, producing just over 82,000 BOE per day and 9% increase year-over-year. This included a 21% increase in our crude oil volumes.

The Marcellus production that was delayed in our third quarter showed up at year end. Our exit production during the month of December was on target at 85,800 BOE per day. Our capital spending and operating costs came in on guidance. Equity based compensation costs declined, which brought G&A costs in under guidance.

Certainly, a weak natural gas price had a significant impact on our business throughout 2012. But the natural gas price dropped into context, our average realized gas price fell by approximately 35% versus 2011. And only a 15% of our net operating income in 2012 was from our gas assets.

Now despite this, we actually increased our fund flow by 12% over last year. And this is largely attributable to the significant increase in oil production, improved netbacks, and gains on our hedging program.

As a result, our adjusted payout ratio improved and we expect this trend to continue in 2013, due to lower capital spending and improved natural gas prices. On the reserves front, total proved and probable reserves increased by over 7% in 2012. Our capital program will replace the 190% of production through the drill bit. And in total, we added over 57 million BOE of 2P reserves, and 66% of those additions were from crude oil and represented 283% replacement of our 2012 crude oil and liquids production.

Fort Berthold was the biggest contributor to our reserves growth. Our total crude oil and liquids reverse increased by 12%, and they now represents 60% of our total P+P reserves. So if we contrast this to three years ago, where oil and liquids accounted for only 50% of our total reserves.

Our finding and development costs were $24.21 per BOE on a P+P basis, and those numbers include future development costs. And remember 66% of our reserve additions were from crude oil as you consider the F&D. We also continue to improve the focus of our portfolio during the year.

We sold non-core assets in Manitoba and use the portion of the proceeds to buy an additional interest in our Sleeping Giant oil fields in Montana. And this had minimal impact on our production, but resulted in net proceeds of approximately $100 million, which we applied to our bank debt, and it’s consistent with our strategy of increasing the focus in our asset base. When we include our acquisition and divestment activities, our FD&A costs were $22.92 per BOE in 2012, which we believe compares well in the industry.

We also updated our assessment of economic contingent resource associated with some of our assets. We’ve identified 364 million BOE of best estimate contingent resource, which is over 100% of our P+P reserves.

Through our development activities we converted contingent resources to reserves at Fort Berthold in the Marcellus, and in our Canadian crude oil assets. We also added a new estimate of contingent resource in respect of our Wilrich play based up on our drilling success this year. And Ian will get into more details on this later.

Now although funds flow increased by 12% year-over-year, we then record a net loss of $156 million for 2012, and this loss was a result of impairments recorded under International Financial Reporting Standards, and are largely the result of lower commodity prices, and principally natural gas, and the fact that we have and will allow leases to expire, primarily in lower quality areas in Marcellus play. The impairments did not impact our funds flow, cash flow or our ability to fund capital programs or dividends.

Now as I am sure most of you are aware, we took a number of steps to continue to maintain our financial strength this year. And those steps include an equity issue, a long-term debt deal, the dividend reduction, along with non-core asset sales, and we ended 2012 with conservative debt to fund flow ratio of 1.7 times, virtually unchanged from year-end 2011. We currently have about $740 million of room available on our $1 billion credit facility.

So with that I will now turn the call over to Ian to provide more details on our reserves and our key assets.

Ian C. Dundas

Thanks Gord. Good morning everyone. As you heard, we finished the year delivering strong reserve and production growth, particularly on the oil side, but more importantly on the back of improving cost structures.

North Dakota continue to be our single largest focus area in 2012, and once again we saw significant reserves and production growth. Production in the region increased by 50% year-over-year and we replaced almost 800% of production through our development activities, adding almost 34 million BOE of P+P reserves.

The F&D cost at Fort Berthold was around $25 a barrel of equivalent including future development capital, with the recycle ratio of 2 times. And although activity levels in North Dakota kept the cost high, through almost to 2012, we did start to see significant improvement in cost performance as we came out of the year and moved into Q1. In the last few months, we have been realizing cost reductions of approximately 15% compared to our 2013 targets. So for our type well, which would be 9,600 foot lateral with 29 stages completed with high-strength province that would translate into the cost saving of about $2 million of well.

We’re quite encouraged by the progress we are making on the cost in this project. And my expectation is that, we will likely be able to sustain its performance throughout this year. We plan to drill 22 to 25 net wells this year for verticals and expect production drills of about 30%. Although, the primary targets of the Bakken, the Three Forks opportunities that continues to grow and we’ll account for about one-third of our D&C activity this year. At current activity levels, we have a drilling inventory in the region should last five to six years.

In Canada, crude oil and liquids production grew by 5% in 2012 through a combination of drilling and enhanced oil recovery projects. Our Canadian oil assets represent about half of our total oil production and already significant source of free cash flow.

Through our technical work over the past few years, we've identified a significant opportunity through improved oil recovery and enhanced oil recovery. A good example of this is our project in Med Hat Glauc C. This is a field that is currently producing about 4,500 barrels a day of oil net to our interest, which is up 70% over the last year as a result of drilling activity, improved water foot management and the initiation of a polymer pilot.

We added 5.5 million barrels of oil equivalent oil reserves in this field this year and cost of $14.25 a barrel. This year we plan to continue drilling and doing some facilities work and we would also expect to make a decision on expansion of the polymer project. Even though we've only started a polymer injection in last May, let’s say, production response has been quite encouraging.

Moving to natural gas, our natural gas spending in 2012 was focused first on lease retention in our non-operated Marcellus project, and secondly, on advancing our understanding of key gas plays in Canada like the Wilrich and Duvernay. On the reserves front, we’ve replaced 111% of our natural gas production and increased our 2P reserves by 2% year-over-year. The majority of this increase came from the Marcellus.

Now, despite Marcellus delays we experienced in the third quarter, we saw a rapid production build over the fourth quarter. Marcellus production increased to average 57 million cubic feet a day in the fourth quarter, which is a 43% increase from where we were in the third quarter and more than double where we were in the fourth quarter of 2011.

The current run rate in the Marcellus is over 65 million cubic feet a day. Much of the activity last year was focused on lease retention. And as retention issues are being handled, we saw activity levels fall quite significantly. We now have about two-thirds of our core non-operated acreage held by production.

We estimate that this year, we will spend around half of the capital level we spent in 2012 again, primarily focused in our non-operated position. Our cost performance in the Marcellus has been slow to improve, as activity has been driven by chasing land expiries, while managing capital in a low gas market.

This combination is typically lent single well pads and less efficient operations. However, we are now starting to see some improvement. We expect, we may see savings in the order of 10% over the next quarter or so. We expect roughly 35% of our total natural gas volumes will be attributable to the Marcellus and are the U.S. properties in 2013. Our netbacks on our U.S. gas production are currently about 25% higher than our netbacks on our Canadian production, which will contribute to the increase in funds while we expect this year.

The bulk of our natural gas spending in Canada was focused on Wilrich and the Minehead area. We drilled two horizontal wells and tied in a third. Our growing success last year has supported an additional 283 Bcfe of contingent resource in the Wilrich.

When we look at our land position we see the potential for over a 100 future drilling locations in this area. Our activity continues this year. We recently completed our fourth horizontal well which tested well. The well was flowing at over 12 million cubic feet a day when we shut it in after 52 hour test.

Finally, we also drilled our first vertical delineation well in the Duvernay and we are able to confirm that we are in a liquids rich part of that fairway. We would expect to drill more vertical delineation wells this year to improve our understanding of this opportunity.

And so with that I will turn it over to Gord.

Gordon J. Kerr

Okay. Thanks Ian. So, well it’s been a challenging year in the equity markets. We have made progress in a number of front, and as we move into 2013 I believe we are entering the year in a position of strength. We’ve improved the sustainability of our business. Our funding shortfall has improved dramatically and we expect to adjust the payout ratios to approximately 125% this year based upon current commodity prices.

We are spending 20% less capital this year. We made significant strides in 2012 advancing the development of Fort Berthold, and the Marcellus and in our oil plays in Canada. Despite slower production growth this year, we anticipate funds flow will grow by about 8% and we are well positioned to benefit from a continued increase in natural gas prices.

We have a solid hedge book in place approximately 60% of our net after royalty crude oil production hedged at over $100 per barrel for 2013 and 28% of our gas production hedged at various price levels through 2013 as well. However, the dividend cut was painful last year, it has helped our sustainability going forward and we plan to maintain our dividends at the current level.

Balance sheet is strong and we intend to preserve that strength. We will continue to rationalize non-core assets in the interest of improving our portfolio and providing additional funding. We’re focused on improving the profitability of our business through increased focus and strong operational execution. We believe our 2012 results reflect our success, and sets the stage for future success.

So with that, I’m going to turn the call back to operator and we’ll open up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Greg Pardy from RBC Capital Markets.

Greg Pardy – RBC Capital Markets

Thanks good morning. A good quarter, I wanted to jump into a few things, just in the past you’ve mentioned how many wells you’ve got in the Marcellus. I’m just curious how many net wells would have got drilled but just not yet completed or tied in rather. And what will the rough working interest on those be?

Gordon J. Kerr

Eric you want to pick the question?

Eric G. Le Dain

I think that we are looking at somewhere in the order book, if you look at drills and drill completed and not tied in, somewhere in the order still probably about 100 plus wells in the portfolio that we are working on.

Gordon J. Kerr

Yeah Greg, the net number on those would be something like 10 to 15 net wells.

Greg Pardy – RBC Capital Markets

Oakley this is just Marcellus correct?

Eric G. Le Dain

Yeah.

Gordon J. Kerr

Yeah, more primarily non-op.

Greg Pardy – RBC Capital Markets

Okay. And what would your working interest there be?

Gordon J. Kerr

That was the net I have given.

Greg Pardy – RBC Capital Markets

Oh I’m sorry. Okay.

Gordon J. Kerr

Yeah, so I mean the effective three partners out there and working interest ranges from 30% to lower 2% or 3% in some of those. So it averages close to 20%.

Greg Pardy – RBC Capital Markets

Okay, perfect. Okay, perfect. Your operating costs in the fourth quarter were really low, I mean I know that there were the one-time severance charges in 3Q, was there anything unique in terms of adjustments in 4Q OpEx wise?

Gordon J. Kerr

I’ll let Ray Daniels to take that question, Greg.

Ray J. Daniels

Not really I mean the four main drivers that we saw in Q3 were either seasonal spend or one-offs. So the lease rentals and property tax is tend to be more in Q3, and then we had environmental and an equalization cost from some non-op partner facilities in Q3. And we did make some adjustments in Q4, and came in under our Q4 budget. But they were the main drivers that made the difference between Q3 and Q4.

Greg Pardy – RBC Capital Markets

Okay, enough and thanks for that. And then maybe just with the Bakken, just trying to get an understanding as to what the rough split in the program this year will be between the Three Forks and Bakken wells or is there intermingling going on right now? And then frankly, we’re just trying to model this or just want to get your thoughts around productivity. I’m assuming the 500,000 barrels is for the Three Forks in terms of the EURs and Bakken is the upper end of that 800,000, but just anything you can provide us there would be helpful?

Ian C. Dundas

Greg, it’s Ian. Yeah, I think the splits as I indicated would be about a third of the D&C activity focused on the Three Forks. So the 20 to 25 wells I think about a third of those Three Forks this year. And we are still moving through this and there is a lot of moving parts relative to the actual density we are talking about and whether it’s a Bakken or a Three Forks. At the upper ends of the 800s would be two long Bakken’s in a 1,280 spacing unit. The lower ends would be the third and the fourth Three Forks wells in that same spacing unit, and that’s directionally pretty good. There is areas they don’t look exactly like that, and some very delay in there. We are still seeing some Three Forks that look a lot like a Bakken well actually, maybe a little more towards the northern part of the acreage block. But I think directionally, the two-eighths of the Bakken’s and the two-fives for the Three Forks is based on a four well per spacing unit, development is a good way to think about it right now.

Greg Pardy – RBC Capital Markets

Okay, perfect. And the last question from me is, just with respect to your transportation at the Bakken right now, what percent would be going on rail and then what percent is going by piping, can you just give us a rough sense as to what the transportation costs are associated with both?

Gordon J. Kerr

Sure. I think the best person to answer that is Mr. Le Dain here.

Eric G. Le Dain

Starting in this February, we are about 30% or so by rail. And our rail is changing a little bit, but probably our total transport cost that’s loading and unloading rail a little bit of trucking to get to the railhead is probably about between $18 and $20 a barrel.

Greg Pardy – RBC Capital Markets

Okay. And then that’s going to Gulf Coast?

Eric G. Le Dain

That is going to the Gulf Coast.

Greg Pardy – RBC Capital Markets

Okay. And then just by pipe?

Eric G. Le Dain

And by pipe, we run on two key pipes right now. We run on Enbridge, North Dakota, one in Clearbrook that’s been in place of course for years. W also ran out the Southwest end on the Four Bears Pipeline, and we run roughly, because remember we are running of course our production from Montana as well as North Dakota through the Enbridge system. And then we'll be also we've taken capacity on the Enbridge expansion that will flow north back into Canada and then back down into the U.S.

Greg Pardy – RBC Capital Markets

Okay.

Gordon J. Kerr

So we've had about 1000 barrels a day going out the west, and we will be somewhere around 7,500 going north and east.

Greg Pardy – RBC Capital Markets

Okay, okay. And then last question from me is just Ian you mentioned that $2 million well savings on the longer lateral, so we now talking more like $10 million drill completed tied in the long laterals?

Ian C. Dundas

Yeah so we are careful how we talk with this good luck the people have different categories here. We’ve talked about the all in DC tie-in every number we could think about relative to that going into that completion at the 12.9 number, I think when you that was in sort of that’s the targeted budgeted number if you will. That probably looks like a 12 or maybe a little less than $12 million D&C in terms of, I think most other people would talk and half of either one of those numbers were pulling back a couple of million bucks right now.

Greg Pardy – RBC Capital Markets

Okay and it's strictly just fewer days in terms of completion there is nothing else that’s changing.

Gordon J. Kerr

It's been a lot of things. Like over the performance started to improve towards the back half of the year and started to see improvement in the drilling side, and so days were falling and so our drilling performance has increased. Of late the bigger changes have been on the completion, and so we are clearly seeing some efficiency gains, but there has been a pretty significant improvement in unit costs in the area on our interest relative to cost services, but it is across the board, Greg, we’re seeing it’s showing up everywhere.

Greg Pardy – RBC Capital Markets

Okay, listen thanks very much.

Gordon J. Kerr

Ray is going to add some color.

Ray J. Daniels

Yes just a bit more specificity around that, the pumping cost and propping costs have gone down, fairly dramatically, and that’s a large chunk of the savings, and we are seeing other sales receipts on materials come down as well to add up to that $2 million.

Greg Pardy – RBC Capital Markets

Okay, thanks again all.

Gordon J. Kerr

Okay, Greg.

Operator

Your next question comes from the line of Kyle Preston, from National Bank. Your line is open.

Kyle Preston – National Bank Financial

Yeah thanks a lot guys, congratulations on a good quarter. Just wondering if you can give us a bit an update on you Duvernay and Montney joint venture initiatives there?

Gordon J. Kerr

Yeah, I think, first of all as Ian mentioned we’ve drilled one vertical test in the area, while in the fact, we just took core in there, as we’ve said we determined we’re in the window of the liquid rich component of this play, and we do have plans to drill probably a couple of more verticals, and we’re looking at obviously what’s happening in and around us, so that sort of leave in, why don’t I let Ian comment further in terms of where we ‘re at in terms of the joint venture activity.

Ian C. Dundas

Yeah, Kyle, we’re sort of saying the something we said in December, our budgets and our plans, and our spending levels assume we will get the JV done. Doesn’t mean, we’re not going to get a JV done, but that’s what we’re assuming will happen. We’re in the process still on those projects, it’s everything probably went a little bit slower towards the back half of the year, foreign investment rules and everything, I think sort of slow down the process a little bit. Now that there’s a more clarity on that, I think it’s freeing up some people to think about what their plans are. We are trying to balance this equation right now, because we don’t believe, we do not need the money this year to advance on those plays, and so we’re bouncing that with where these plays are in this data delineation.

As Gordon said in both of these plays, we have one vertical well into each of them. When we look at our activity that we’re playing this year combined with offsetting activity, which is increasing pretty rapidly, both in the Montney and in the Duvernay, we see a lot of information coming our way. So that’s what we want to leave the people as we’re really encouraged by what’s happening in both of the plays and we’re still working through that process.

Gordon J. Kerr

I think that – and I think it raise well where time is to a certain degree relative to ten-year our trend here, so we can face things appropriately, and certainly, we would like to bring in some funds associated with both of these plays in some form of fashion sale or joint venture. You mentioned the outcome of the next deal, I actually think that for us, it’s quite encouraging, because the course of public was put more on the oil sands. and then of course, see the Encana deal certainly doesn’t hurt us in terms of view of value in the play area. So we think there’s great opportunity here, it’s matter of a timing more than anything.

Kyle Preston – National Bank Financial

All right. Thank you.

Operator

Your next question comes from the line of Dirk Lever from [AltaCorp Capital]. Your line is open.

Unidentified Analyst

Good morning, and good results. I just wanted to follow on what Greg was asking, and then has to do with the operating costs. So you came in at, so around ballparks, nine and a quarter. How do you see your cost structure going forward on the operating cost side, and let’s kind of average it out, I understand the Q3 costs are property taxes et cetera?

Gordon J. Kerr

Well, first of all we haven’t changed the guidance that we put out earlier this year, Derik so we are still holding to $10.70 per BOE operating cost. Is there opportunity to improve? Well, I can tell you in terms of where we put focus and time, it is to look at how we can improve in all other areas in terms of costs, but right now we haven’t moved off the $10.70.

Unidentified Analyst

Okay. And I will just leave it that and thanks very much.

Gordon J. Kerr

Okay.

Operator

(Operator Instructions) Your next question comes from the line of Roger Serin from TD Securities. Your line is open.

Roger Serin – TD Securities

Thanks. Good morning everybody. Some of my questions have been answered, but I have got some modeling questions. Taxes were lower than we might have expected in the quarter. Have you got any sort of change on guidance on taxes for 2013?

Gordon J. Kerr

Rob will take that question, Roger.

Robert J. Waters

Roger, it’s Rob Waters. Our current guidance is that, we don’t expect any material Canadian taxes in 2013, and on our U.S. operations, we would expect cash taxes to run at above say 3% of our net U.S. cash flow or revenues less cost. And yes it came in a bit lower than 3% I guess in 2012, but whether it’s 2% or 3% it’s sort of a rounding error. Compared to last year, you might have seen higher cash taxes in the U.S. and I think that had to do with we sold some Marcellus assets, and had a capital gain that we weren’t able to shelter down there, and so we did pay some capital gains tax in the U.S. if you are sort of looking at that 2011 compared to 2012. But I think we are back into 3% of U.S. cash flow for this year in terms of a cash tax number.

Roger Serin – TD Securities

Okay. Moving on to…

Gordon J. Kerr

I just add one other thing is that, the taxes we’re seeing in the U.S., they tend to be AMT taxes, which are the Alternative Minimum Tax in the U.S. So they can be recovered to the extent that we do pay taxes in the future. But there is a certain calculation you have to do that you have a minimum level of tax. So they’re kind of like prepaying your tax right now.

Roger Serin – TD Securities

And what I look at net revenue is being net of interest that you allocate or just funds from operations at a property level think of it?

Gordon J. Kerr

From a tax perspective?

Roger Serin – TD Securities

Yeah, from a tax perspective?

Gordon J. Kerr

I think there will be a certain element of interests on both sides of the border in terms of our tax calculations in that. So you would think of it that way, but I didn’t still know I could tell you definitively or even split that up. But Roger, we could spend some great detail time and even try to help you on your modeling there.

Robert J. Waters

Roger, you to come over.

Roger Serin – TD Securities

I have another question for Rob. So what is economic relevant to derivative settlement, on senior note repayment. There was a sort of a cash, it look like cash receipt based on that maybe we should take that offline?

Robert J. Waters

Yeah, I’m not pretty sure what you’re referencing, Roger. We could take it offline.

Roger Serin – TD Securities

I’m not sure what I’m referencing either, so we’d better take it offline. Okay, I got one other relevant question, relates to G&A guidance for next year, which is $3.15, if I look at your mid range of your production, so $3.15 of BOE, I like what you did in 2012 that would imply about a 15% increase in G&A costs from 2013 over 2012. And is that just the way the numbers have come through, or you actually expecting to see a meaningful pickup in cash G&A costs year-over-year?

Robert J. Waters

Well, first the cash, I mean we've added step in our U.S. operations to help advance in the organizations initiatives done there. When you combine it with the equity based, certainly we are looking for an improvement in the total based on equity performance. So that's a good news story if we come to that…

Roger Serin – TD Securities

Okay.

Gordon J. Kerr

Roger, when you say that…

Roger Serin – TD Securities

Sorry?

Gordon J. Kerr

Roger, when yo say G&A, are you including what we call equity based compensation expense?

Roger Serin – TD Securities

I was using a 31.5 number and I don't believe I was including the equity based comp on that, so we can take that offline Rob…

Robert J. Waters

Yeah.

Roger Serin – TD Securities

When you explain all the other stuff to me.

Robert J. Waters

Yeah, actually Roger, that does include the equity based and it comes back to what I just said a moment ago.

Roger Serin – TD Securities

So you are putting, you think your stock price is going up?

Robert J. Waters

Yes, I think I was trying to get to, because, if you look at the details on the guidance, it will have a split of $2.70 on the cash side and 45 per BOE per equity based comp.

Roger Serin – TD Securities

Perfect. That’s what I needed.

Robert J. Waters

Okay.

Operator

And there are no other questions at this time. I will turn the call back over to your presenters.

Gordon J. Kerr

Okay. Well, I want to thank everybody for joining us this morning. We are obviously, we are pleased with the results and the feedback we are getting so far as that the analytical community are pleased and we are looking forward to 2013 and improving on all front. So thanks for joining us.

Operator

Ladies and gentlemen, thank you for your participation. This concludes today’s conference call and you may now disconnect.

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