Diversified Energy Co (DEC) 2018 Q2 法說會逐字稿

Well, thanks, everybody, for coming. Thank you, everybody. You probably saw the earnings release this morning that went out. The RNS went out 7 AM, recently in the door, which shared the half-year results and then also the dividend declaration for the fourth quarter. What we like to do today is really just to -- I'm going to open it up, go through a few slides, just hitting the highlights of the first half of the year. I will turn it over to Eric to go through some of the numbers more formally. I will come back up, share a couple of operational things with you, and then we will have a presentation on the decommissioning liability, plugging and abandonment costs.

And then we have a treat for you because we actually ended up bringing our third-party reserve engineer -- independent reserve engineer with us, who will present a little bit on the reserves in Appalachia, but also on the decommissioning and his third-party independent review of that. So I think that will be helpful for a lot of the analysts, and also for the institutions that we go see this week, to kind of give them some flavor around that and really show how that's calculated and the true liability associated with it.

So with that, we'll go ahead and kick it off. And then we will have a Q&A session at the end for anybody who wants to ask questions.

So the first half, really good half of the year for us. As you guys know, since we've IPO'd that a big part of our strategy is the acquisition of assets in the basin that have been neglected, kind of forgotten. We've acquired a lot of assets in the last 1.5 years, and they are really starting to make a true impact on the financials and starting to flow through the numbers. The first half EBITDA of just slightly under $23 million, that was up from the second half of 2017 which was $13.5 million; and for year on year, $4.1 million, a 69% increase.

Average daily production was up 450% since last year. We are at 19,300 barrels; that's what we averaged for the first half of the year. Of note though is that with the EQT transaction that we've closed in July, the July exit rate is 60,000 barrels a day. So a significant increase year-over-year and definitely right in line with where we told people we would be. EBITDA margin is 40%. That's where it's been. We hit that about the June mark of last year and have been pretty consistent with that. What I will tell you, with the EQT transaction, this is set to jump to 60% based on some factors that we have talked about.

We closed the Alliance Petroleum deal in March. We closed the CNX resources deal in March. Those were the two first-half transactions for about $180 million. And then we had a $189 million equity raise in the first half, which we closed in January, which fully funded these two acquisitions. We talked about that when we were doing the roadshow for those transactions. That resulted in us being able to refinance the credit facility from a high-yielding product down to a normal revolver at LIBOR plus 2% in the quarter. So we significantly reduced our borrowing costs.

Recent events. This morning, we announced the 2.8 cent per share dividend which was up 62% from the first quarter dividend that was -- that's being paid this month. That would represent about a 9% dividend yield on the second quarter average share price of 91p. I think even at current price, that's about 8% dividend yield. We closed on the acquisition of the EQT assets for $575 million. Talked about the increase in the margins from 40% to 60% based on the midstream asset revenue and the fee-based income off of those. The balance sheet and liquidity strengthened, still at two times levered but slightly under that. And we enlarged our credit facility up to $1 billion, with $600 million available. Right now, we have about $190 million of liquidity.

So everything is moving in the right direction. I think, really, the main thing that I would tell you coming out of the first half into the second half is that we anticipate that the second half of the year to be a very, very good second half, significantly above and beyond the first half. With the EQT transaction flowing through, the CNX and the Alliance Petroleum being fully in the numbers, second half of the year is set up for a very, very good second half.

Talked about all this for the most part, but we are seeing positive trends. We've got a schedule in here that Eric can talk about a little bit more later, but really just kind of laying out all the key metrics in terms of the pro forma if EQT transaction would be in there for the full year. But these acquisitions are having huge benefits to the numbers. The cash flows, our operating metrics per barrel of oil, equivalency, and per Mcf are all going in the right direction. The integration of the assets is going very, very well on plan. We will continue to work on the EQT as we move throughout the rest of the year. And we are well-positioned to transact complementary growth opportunities as we move forward.

The pipeline of opportunities continues to be very robust. We are seeing what I would consider to be an acceleration of the plans of these large shell players to move non-core assets off their balance sheet. And at sometimes that's at the expense of price. I mean, they're not even really focused as much on the price as much as they are getting rid of non-core assets and reinvesting money back into the shell.

This is a timeline of the first half of the year. I was kidding Eric earlier, I don't know what in the world they were doing in April and May; it looks like it was pretty weak. But you can see it's just been a very, very busy first half, from the equity offering to the closing of the two transactions, refinancing the credit facility and then refinancing it again after the EQT transaction, and then also doing another $250 million equity offering back in June.

So that leaves us where we are at today here in September. We are integrating assets as it relates to EQT, which, as you can see, EQT has been a tremendous, tremendous asset in terms of -- we had a couple of meetings earlier this week, and I told people that I feel like EQT is the biggest gold mine that was out there. Right now, it's looking that way.

All these things are low decline, predictable production profile. The high liquid content for the first time which gives us a different revenue stream than we've had up to this point, and increasing our exposure to oil, giving us significant take away that -- this can't be stressed enough in terms of the gas that we are producing on that EQT transaction in terms of the markets that is made available to us in terms of TECO and East Tennessee. A lot of near-term achievable operational efficiencies which we have already begun to look hard at and gives us a significant cost of capital advantage when it comes to competing for assets in the market. And you can see all the step ups in production and EBITDA and all the other things that the acquisition is going to provide.

I'm going to turn it over to Eric, let him talk about the financial results real quick.

Thank you. Needless to say, it has been a busy start to the year. But as you'll see in the numbers, you will really begin to see this flow through in a very positive and powerful way. But we'd like to remind that growing for production and for production's sake, or growing the asset base for the sake of just getting bigger, is never our objective. It's really about looking for the right type of assets that complement what we think is a very high-quality portfolio. And so to really meet our criteria, they need to be mature, long-life, stable producing assets.

What gives us an advantage is that, as we have gotten larger and larger in the basin, the ability to bolt on assets that meet that profile becomes easier and easier to do. And so when you add in the advantages that we have achieved or the cost of capital, it certainly puts us in a very strong position to continue to transact very successfully.

As Rusty said, obviously, year-over-year production growth of 450%, sequentially another 100% as you layer in the EQT transaction, exiting at a very strong 27,000 barrels a day, which, based off of the pro forma results that we have put out before, represents about a 4.5% decline. So nicely within that 4% to 6% per year decline rate that we talked about. And then exiting July, once you bring those EQT assets online, at over 60,000 barrels of oil equivalency per day. As you'd expect, that shows up in revenue.

And we look at this really on a unitized basis. So relatively flat, period over period, based on the legacy assets at [16, 14 and 16, 19] per BOE. But what you see is, as Rusty talked about, that exposure to the oil and the liquids rich content of the EQT production stream, a significant uptick in realized price as we're able to realize that liquids content, adding almost $2.50 per barrel of oil equivalency. So while high revenue is going up 14% on a unit basis, importantly, we are doing what we can to really control costs because we pride ourselves on being a more efficient owner and steward of these assets than they were in the hands of EMPs because they were focused more on the drill bit than on managing mature production.

And you're seeing that show up in our results. Relatively flat, period over period on LOE, slight uptick just as it relates to bringing assets that have been neglected in the hands of the previous owner and putting those into the condition that we like to operate them in. And so you will see that trend in the proper direction under our care, certainly bringing in the EQT assets which benefit from having the midstream assets and a different call structure associated with those, significant tick down in OpEx, going from an LOE down 36%.

And then as you think about our administrative expenses, we are taking the team. We are doing some strategic hiring to put us in a position to optimize and manage the portfolio. But on a unit basis, a significant tick down, going from $1.51 per BOE down to $1.20.

It should show up in our earnings and it does. We talked about the fact that, again, in order for a deal to be attractive to us, it needs to be accretive on a per share basis. And you see that show up not only in just absolute EBITDA growth, on an unhedged basis at $223.3 million increasing on a pro forma basis to [$108 million], but, importantly, on a per share basis, while we went from $0.08 to $0.09 sequentially, the step up, very meaningful, bringing in that low-cost debt financing to partner with equity funds on the EQT transaction to take EBITDA, on a per share basis, up 133% overall. But on a per share basis, much more so, to that $0.21.

And you see also on the side, where we are giving you a build-up and showing how we ultimately take revenue, match it against all of our cash operating costs to result in a 59% cash margin on this business pro forma. Then at that 40%, as Rusty said, period over period on the legacy, but that nice step change coming in with the liquids content and then just the underlying setup of the assets that we acquired with EQT.

All of that goes to support the dividend. We have prided ourselves on being a different opportunity in the EMP space, or really the energy market here [in aim], and that we are a consistent dividend payer. We moved the first quarter of this year from a half-year dividend, or a quarterly dividend, to show that consistency of cash flow, moving from a $1.7 cent dividend -- that will be our first quarterly dividend, is paid this month in just a few days -- to declaring, today, our second quarter dividend of $2.8 cents, which is 62% higher on an annualized basis, just over $0.11 per share, and at current price, as Rusty said. And for the second quarter, it was a 9% yield, but even now it still is around an 8% yield. So very, very strong. We have given a dividend schedule that you could expect future dividends to be paid on.

As we turn to the balance sheet, needless to say, we've got a very, very strong and large platform of oil and gas properties, going from just under $0.5 billion at the end of the first half of the year, with the introduction of EQT at just under $1.1 billion. But we've also done that while enhancing liquidity. With the enlarged credit facility of $1 billion, with a $600 million borrowing base, just under $200 million of that remains available today, up from $65 million at the end of the half-year.

But we haven't risked the balance sheet to accomplish all of this. We have said from the start that we are very mindful of the balance sheet. We want to stay on our front foot as we do continue to look at complementary acquisitions. To do that, you have to make sure that you have a healthy balance sheet, and that's done through maintaining a very healthy leverage ratio. Ended the half-year at 1.7 times, but -- even with the introduction of about $300 million of additional debt with the EQT assets because of the quality of earnings that we acquired. Because remember, these are producing the assets and not undeveloped where you have to go spend to generate that cash flow, see that leverage tick up to just 1.9 times. So still below 2 times and nicely within that 2 and 2.5 times ratio that we say we want to operate the business at.

But there is still liquidity on the balance sheet that if we see complementary opportunities, we have the ability to hit that down without coming back to the markets to introduce additional dilution. And as you would expect, with the reception we've received in London, the equity on the balance sheet has also increased just over $90 million at the end of the year, up to $300 million at the half-year, and sitting today at about $550 million.

So as you think about our capital structure, quite clean with just the revolver outstanding. And prior to this year, we had the Angelo Gordon facility that you'll recall was just around 10% coupon. We cut that in half with the credit facility that is at LIBOR plus a spread of 2.25% to 3.25% depending on utilization which was under 5% at the half-year. So very cost-effective and gives us a nice five-year horizon to think about the capital structure that we think ultimately makes sense for these assets. But a very flexible piece of financing that allows us to not only draw down when we need it, but we can also pay down to avoid interest expense as we do throw off incremental cash flow depending on the timing of additional opportunity.

So protecting the dividend is obviously a very important part of our business. And to do that, we have always talked about hedging being a key piece of our strategy. We continue to include in the presentation, within the appendix, the gory detail that goes into the hedging portfolio for anybody that is building a model, but really wanted to step back and help people think more holistically about the way that we approach hedging. And so we have outlined the five main components of the strategy.

And the first is the target level. So we target 75% to 90% of our net PDP production which gives us a very stable cash flow stream from which we can then predict our dividend. The duration of our portfolio is for 36 months, or 12 rolling quarters, and it is a rolling quarter basis. So as one quarter rolls off, we have a period of time to put that next quarter on. In doing that, we keep it very vanilla; we don't get cute with respect to the transactions. We use costless collars, swaps, and we have introduced using some deferred premium puts as well, as we are on a backwardated curve we won't -- that floor protection, but we'd like to have some ability to participate more in the upside. So you're seeing a mix of these structures to do that.

Fixed versus physicals. We like engaging in fixed contracts with purchasers which gives us an all-in, truly realized price that provides greater certainty. But the fixed market tends to be a 12- to 18-month in duration. So as you go further out, we do begin to use more of the financial hedges. And when we do that, the fifth point, we use a combination of NYMEX and basis differentials to get an all-in realized price that we can expect to achieve.

I will say that, basis, if you follow the basin, typically has been very narrow in the winter months when heating demand increases, and it tends to widen out during the summer months. But you are beginning to see a couple of things really improve that. The first being is the United States has shifted away from the use of coal to generate power, and natural gas is stepping in to fill that void; cooling homes in the hot summer months is actually generating significant power consumption during the summer months that has caused that basis differential to narrow; and then there have been an uptick in offtake pipelines in the area, Sunrise and others, that are allowing us to move excess gas out of the region from the Marcellus and others. So we are certainly seeing positive indications with respect to basis differentials.

So all in, I think a very, very positive platform, as Rusty said, to enter the second half of the year, a very strong trajectory. And Rusty will talk a little bit about some of the operational efficiencies we have already achieved.

Thank you. So some of the things that we have had some questions in the past about what do you guys do to get wells back in production or increase the production off of the wells. And so we went through, and just want to highlight a few of those things that we have done. These are real life examples of things that we have done here in the last several months.

But number one, for example, wellhead compression. We took a compressor that was running on one well, and we took eight wells in the vicinity, put them behind the same compressor, and increased production by 38% on those eight wells in total. We took a wellhead set up and took a sensor, relocated it closer to the well -- I love these pictures, don't you? -- relocated it closer to the well to significantly increase the time that the well is up and running, and increased it by 140%. This one here, our well is out of production 11 months out of the year. The gas on the [4.5] would only feed one month. What we determined was, on the annulus, which is on the back side of the well, that there was a significant amount of gas on the annulus, that when we hooked it up, kept the well producing 12 months out of the year and was 100% increased in production.

Plunger lift setups. We do this a lot. We put a lot of plunger lifts, which is nothing more than artificial way of keeping fluid off the well. But those have significant impacts on wells that have a small amount of water on them that impedes production. Treating wells with water and chemicals increased; in this case, it was up 126%. Pumpjack installations. Taking wells that -- running tubing; putting pumpjacks on the wells; helping to keep the fluids of the wells; more consistently, increasing production. These are all ways that when we take over the wells that have been neglected, that we were able to increase or put the wells back into production.

In the past 18 months, we have put 524 wells from these three transactions, and we just begun on this one, but we put up 524 wells back in production that were not producing when we bought them. So you can see that, a lot of times, when we're buying these asset packages and they're showing zero producing wells, it doesn't mean they can't produce; it just means they haven't been produced. And so this is a very good example of that.

I'm going to let Eric spend about five minutes now on the P&A summary and on the decommissioning liability issue.

So, obviously, that last slide where Rusty talked about putting 524 wells back into production, not all of those are necessarily ones that we expect to move the top line, because a key part of our business is managing that decommissioning liability. And the states have very, very low minimum production standards; it can be as low as 10 Mcf per year in order to qualify that well to continue to be a productive well.

So whereas the previous operator may have done that and shut it in for 11 months out of the year and turned it on for 1 in order to get that production, we've, as Rusty said, highlight ways that we can ultimately get that well in production whether it be -- even if it's at a low level, for 12 months out of the year. But we can certainly do a lot with well management to reduce the number of wells that show up on a plugging list that the state would have.

As part of this, we know there's been some questions that have floated around about what decommissioning really is, how we think about it. And if you go back to the end of last year, we plugged a handful of wells for under $10,000 apiece, where we recognize the portfolio has evolved rather dramatically over the last three months. We have entered states that we previously didn't have operations in. We've got a variety of types of wells across this enlarged footprint. And so we have taken a step back and done really a ground up analysis on what we expect these wells ultimately cost to put to bed at the end of their life.

And so we show how those costs come together. We have given a detailed sort of -- if you think about a type curve on a newly drilled well, this is a type AFE to decommission a well. And you see that we expect -- and this is pre-salvage, so this is we think a very conservative number, but the pre AFE levels depending on the location and the type of well, anywhere from $20,000 to $30,000 per well. So certainly, I think very achievable numbers that we will continue to improve upon as we improve or build a larger body of work and develop efficiencies in this space.

And to give some real world examples about how different this can be from the hands of one operator to the next, we focus on a well that we just plugged from the -- on the EQT assets previously and that the EQT have put out, and they were plugging these wells for $45,000. And we asked our guys to take a look at that design, the plugging design, and see what they can do in the first well that they plugged under our watch. And immediately took that down nearly $17,000.

And to do that, one way we look at it, we said, well, we have a dozer that we use to manage our own sites today. So we use our own dozer to cut down the dozer expense. We tailor the cement on the job to the specific specifications required by the state as opposed to using a one-size-fits-all. And then we improve cycle time. We plug the well faster , and ultimately we're able to reduce the rentals associated with that job, shaving a significant amount of cost off of this well. And we think if we can do this on our first job, you'd certainly expect that as we build a larger body of work that we would only build on the success. And I think you have seen the industry historically do this.

If you think of where unconventional development was at the start of drilling horizontal wells, they were very expensive, and their productivity was nowhere near where it is today. Certainly, we will become one of the largest plugging companies in the basin as we have the portfolio that we do. And we expect to get really, really good at plugging these wells. And so we believe these are numbers that we'll ultimately be able to beat.

If you look at our overall portfolio, we have given a breakdown of our wells by state. And importantly, down here below the bar graphs, we have shown the average depth of these wells, depth being a real key driver with respect to the expense. And you'll notice in the first bullet, we point out that 87% of our wells we expect to plug for $25,000 or less, and that's because the average depth of the well in our portfolio is less than 4,000 feet deep. So shallow by industry standards. So certainly, we think a very, very manageable portfolio. But what does all this mean?

We distill this back to MPV and the PV-10 in ounces. If you think about the way that we report our reserves, PV-10, post EQT, we have $1.4 billion -- just shy of $1.4 billion in PV-10. So if you take those AFE cost assumptions that we outlined, and you apply that same 10% discount based on the schedule that we put together, you can see over the next 15 years the present value of those cash flows is just over $16 million. And on the entire portfolio, if you take our plugging program out over the next 75 years, at the end of which we'll have plugged all 53,000 wells, the PV-10 of that number is $46 million. So it certainly helps to put it into context when you look at the overall reserve value that we have.

Now the PV-10 analysis is designed to put that on par with the PV-10 analysis of the reserves. But it does show up differently on the balance sheet, because you are required, under the accounting standards, to incorporate an inflation assumption. And rather than using a 10% discount factor, you are required to use the company's weighted average cost -- or risk adjusted, rather, cost of borrowing. So for us, the inflation factor is going to be consistent across any operator. And that's for -- we use the Livingston survey. Any public company is going to use some published index. It could range anywhere from 2% to 2.5%. For the last two years, that's been 2.5% for us. And then our weighted average cost of borrowing when you risk adjust it would be 8%.

So if you take the $46 million discounted PV-10, and you add that inflation factor over the duration of the portfolio, that steps it up $35 million. If you then change the discount rate from 10% to 8%, that increase is at an additional $55 million. So the number, if we were to record this today and we're still wrapping up the analysis and you would see this on our year-end balance sheet, would be around that $136 million to $140 million number.

And I think it puts it in perspective. When you hear people talk about the liabilities that were ultimately recorded on CNX's balance sheet or EQT's balance sheet -- interestingly, it's a bit difficult to go back into public company's filings and find. These assumptions aren't generally published. You can very easily get back to the inflation factor, but the discount rate, you could guess at that, on a larger company it might be 6%, and that would be a significant change from our 8%, on a smaller company that could be 10% or 11%. So it really just depends on the individual operator. But I think the other two are the per well cost assumptions and then the duration over time that they ultimately expect to plug these wells.

In the hands of the operators that drill these wells, they tend to put a 25- to 30-year life on them and accrete to that period without really looking back to say what's the engineering data telling us is the true productive life of these wells. We have done that analysis and we've talked about these are long-lived wells that were produced for 40 to 50 plus years. So when we put those factors together, you can see how we ultimately get back to that $140 million number that we feel is a very achievable and realistic number.

So just to wrap up on this part, and then I will turn it over to Randy for a 15- to 20-minute conversation about our reserves and his analysis on the P&A. But, really, the first half is really just solidifying what I've been saying as I have come to the market the last 1.5 years. We are going to acquire assets; we are going to acquire them at a very favorable valuation. We're going to do better at operating those wells. We're going to get -- be more efficient. We're going to put wells back in production. We're going to lower our operating metrics on those wells, and we're going to bring every piece of cash flow out of them that we can over their remaining lives.

That's our -- our model is proven. I have been doing this since 2001. We have been doing a very, very good job of that in the last 1.5 years, and we're staying disciplined. We are not risking the balance sheet to do this. We are keeping our leverage in check, staying at that -- around that two times levered. We are financially strong. We have got a healthy balance sheet. We've got liquidity of $190 million. And we are paying our dividends just like we said we would. In fact, probably at a higher pace than what -- than even what I anticipated at the time. So all these things are really continuing to solidify the investment opportunity that I laid out 1.5 years ago.

I'm going to turn it over to Randy, let him talk a little bit about his presentation, and then I will come back and wrap it up; you can ask any questions. Thanks, Randy.

Oh by the way, just so you know, Randy is considered the expert as it relates to reserve engineers in what we consider to be Appalachia. He can talk to it himself, but he has been doing this a long time. He has a significant client base in Appalachia especially, and he has been doing ours now for -- how many years?

Since 2010.

So seven or eight years now?

Yep. Thank you. It's my pleasure to be here today. Thank you for attending the presentation. Wright & Company Inc. was formed and are founded in 1998. So this year, we celebrated our 30th year doing reserves in economics. We have prepared all of the reserve estimates for the CPR that have been filed over in this area through [aim], and we spent a lot of time looking at a lot of different ideas.

So in your presentation, you have a little bit about the background, our uniqueness of what we can bring to the table as far as our experience, our unique position in that we are third-party independent appraisers. So we represent a large number of clients throughout all of these major plays and the shale plays currently throughout the United States. We are located in Nashville, Tennessee. I have been evaluating Appalachia top reserves [for three years --] four years, previous financial institutions, [and things are like that] for about 45 years. So right now, [it's 30 years] but I've got about 45 years of experience. I know I don't look like it's possible, but maybe you would expect I had 60 years of experience the way you look at it.

But at any rate, there's two major issues that I've taken as part of the special presentation today for your benefit. One is everything that we are talking about is based on our long-life, low-terminal decline production profile in Appalachia. These wells -- many of these wells were involved with Rusty, as we said earlier, since that 2009 or 2010, of which all of these acquisitions occur. So Wright & Company did the front end due diligence before they made offers on all of these potential transactions. So we came up with our own. This past midyear, I guess, we prepared a CPR for the legacy assets and a separate evaluation of the EQT assets we disclosed in July. So we are under two months of merging in the EQT assets, but we have addressed that we have put it in our master database, and we have a consolidated evaluation.

However, if you begin to look at the typical long life well in Appalachia, if you're not familiar with it, it comes on at a reasonably high rate, not in terms of what you're reading in the marketplace now through the literature of the shell rate. I spent many, many years discussing with some of the major current Marcellus and Utica shale players trying to determine if their typical well had an ultimate recovery between 120 million and 150 million cubic feet, ultimate recovery over a 50-year lifespan. The rate was 3,000 a month or 4,000 a month. Now it's at -- you read about the Marcellus shale where they're coming on millions of millions a day and they're producing for a long life.

But the typical profile is it comes on with a higher initial rate that follows a hyperbolic decline until it reaches a terminal decline which we characterize as a shallow exponential decline. And this example is 3.5%. We have done many, many studies for major companies. We have done studies for Statoil, international sea nook, Sumitomo Japan, sea nook out of China, [Samcholi] out of Korea, as well as some majors in the United States, such as Chevron, who did not understand low terminal decline. So we have done special studies for them to demonstrate how this works overtime.

So this is a map that just briefly shows all of the properties for our diversified, but I pulled four examples. And these are just random examples. But if you go through all the 55,000 wells, they look very similar depending on their age. And you will notice that here is a -- on the upper left has 37 years of production, much of which is a 3% decline. The Pennsylvania vertical well on Allegheny County has already 28 years of production. The vertical on the lower left, West Virginia, has 30 years of production at a 3% decline. One of the Pennsylvania horizontal wells in Fayette County that was in one of the acquisitions has 28 years of production, and we've projected it through a 3% decline, and we will talk a little bit more about how we make those projections later.

So if you look at some of the wells, with over 17,000 wells in this dataset, and these 17,000 wells came out of the dataset for diversified as we did our analysis, 74% of those 17,000 wells are producing less than 6%. And you see the largest majority fall between 3% and 4%, with 7,400 of the 17,000 wells already below 4% or less. These are examples of the same wells that were on the first slide that I showed you. The Ohio vertical, which, like I said, have 37 years of production. So when we say that these wells have 30, 40, 50 year lives, we are talking about from the effective date of today.

So if this well has 37 years of production, we are projecting it to produce still above what the states require minimum levels for production and commercial ability, [commerciality] of selling gas. We are projecting the life of that well will have 93 total lives. At the right, 64 years; total lives on the lower left is 79 years; and 86 years plus on the horizontal wells in Fayette County. So when we are talking about 30-, 40-, 50-year life, don't think that, okay, they have already produced 37, does that mean I have 13 left? No. No, it does not. We are saying 50 years [from] plus the 37.

Now that becomes important because the second part of our study was the abandonment study that we took from an independent approach. Wright & Company is fortunate in that we have exposure to many, many securities and exchange reporting public companies in the United States. We have much exposure to the financial communities that make investments in these companies, the private equity market. We do a lot of independent work for them before they make commitments to any of the major basins, Marcellus, Utica, the Eagle Ford. All of the focus there has been in the last 10 years if you keep in mind.

You think you know those are long plays, but they are not. Eagle Ford was the [play du jour] of 2011 or 2010; the Marcellus or the Utica was 2012. So we are going five or six years into those plays. But this play has been already around for many, many years, many, many decades. Some of the wells have been productive over 80 years already, and we still see that they are profitable [to make]. So that becomes very important. The reason we put them in to this study or this presentation is that becomes very important when we look at the timing of the decommissioning and asset reduction of liabilities or when the cost to -- would be incurred to plug the wells. And we're talking about many, many years even from today as they [produce it].

Wright & Company took the approach that we wanted to look -- and these are all of the properties, and they are color-coded on the upper left as you will see. And we will define what those color codes mean. But it became important because, as we said, not only timing, but depth, complexity, location, all of these things that may play a major role when you begin to look at plugging and how do you abandon a well. The type of the well, vertical or horizontal. Whether it's in an area where coal is present, well, that requires different things to plug a well over a coal scene.

All the different state regulations, Wright & Company, particularly recently, in this study, contacted every state that we have assets, diversified those assets in, and we looked at and talked to, and at the end my presentation you'll have the websites if you want to go on. We have contacted all of these people, of course the condition of the well. To abandon a well, it takes certain permitting time, it takes well P&A, which is the major cause of removal, disposal of facility equipment, waste and site reclamation which should not be overlooked in the total cost.

So we based our studies on, the last one that I would say, Wright's proprietary data and experience. We have a lot of experience with a lot of operators that do this on a regular basis, and they have, and they carry in their SEC filings the abandonment consideration [that they do].

So we have broken it down into these particular areas by name. So you got approximately 55,000 total wells. Well, this is where they are located. This is just a quick map of where they are located and how many. So for example, in Ohio, you got about 8,000 vertical wells. In Pennsylvania, you got about 19,000 wells that are in the coal area of southwestern Pennsylvania; 1,500 wells are in the noncoal area, mostly in the northwestern portion of the state. And I will show you that when we get to the map.

So here is the color code, and you begin to see the Pennsylvania -- these are legacy assets all in here. Pennsylvania coal is one color in the north (technical difficulty) okay. So this is the area of the Pennsylvania coal. This is the area of Pennsylvania noncoal with Ohio and West Virginia as you will see that. The blue dots represent the few horizontal Marcellus wells that are in the portfolio for the legacy assets that were obtained when the [heightened] acquisition occurred last year.

So we began to look at this and we said, okay, these wells have different well costs. What are the well costs? What's it going to cost? So we didn't want to just pick one number we wanted to look at. So for example (technical difficulty) right here you got the Marcellus. So we estimate it's going to cost about $90,000. Well, that's not a large number of their portfolio, but that is a consideration that goes into the total because they're going to be out there sometime that you're going to potentially have to plug those.

You look into West Virginia, you see a typical vertical well in West Virginia may cost $35,000 roughly. And in vertical Ohio, $20,000 to $25,000. And so we came up with an overall weighted average of the legacy assets and had a weighted average of just under $30,000 per well is what we would expected to be carried on a weighted average basis. So then we layered in the EQT properties. Well, there's about 12,000 wells in the EQT properties, located mostly in West Virginia, Eastern Kentucky, and Virginia. Well, these states -- well, West Virginia was included in the legacy, but Kentucky and Virginia were [near].

So we had considered what the plug-in cost would be for those areas. And so we looked at each state. So after we contacted the state, we looked at our client list, what they were reporting in their SEC filings so we would be consistent. We took those numbers, so you have got, in Kentucky, for example, your vertical Kentucky wells, we estimate about just under $30,000. There's coalbed methane in some of these areas. So that requires another look similar to the coal in Pennsylvania because it got coalbed methane. Well, we know that our clients have plugged us into those wells in Virginia -- [this is in] Virginia. I know the state got covered up here.

But this is Virginia, and you look at the coalbed methane. So we estimate about 27,000 for the number of coalbed methane wells that were going to be plugged eventually. There were some acquisition of this and horizontal Marcellus and West Virginia, so we used the 9,000 again. There are other horizontals in West Virginia that's a lower (inaudible) and different formations that have been also not Marcellus, but other horizontal wells, so we estimate about $75,000 per well there. So we came up here with a weighted average cost of about $33,000 plus -- $33,000 to $35,000.

So ultimately, we found that the averages were between $30,000 and $35,000, as you see, to plug all the wells over the lifetime of the property.

So as you begin to look, there were certain assumptions made. We looked at all the wells and how long it would take them to reach the minimum that's required, and then we talked to [diversify it] who then is in the process, as you have been told, working out agreements with certain states where they've got obligations that appear to be more immediate. But those things are being renegotiated. So based on what we think currently this is the drilling schedule, it ramps up beginning in -- between after 2030 up to about 1,000 wells a year. These are annual basis. And they go up. And as Mr. Hutson said, we've got a total -- all the wells are plugged here in [2028].

Now I will say, that in our study, when we looked at how many wells could still be productive above the state minimum levels, at the end of this plugging schedule, they are all included here for liabilities and estimates of plugging costs, but there's about 8,000 of the 55,000 wells that are still above the minimum [rights] required for plugging at the end of this schedule. Now they have been included here within the 1,000 wells a year just to get them all taken care of. So we didn't ignore 8,000; they're all included here.

So we have been -- did a similar evaluation with our average cost and the drilling schedule -- design drilling schedule, but with different costs, and we came up with a present value discount at 10% of about $60 million. So that was our number based on our costs and our studies.

Again, here is your reference. And I thank you for your attention. And I'm available for any questions that you will have later.

So just for purposes of the presentation that Eric did, so their number was $60 million. If you remember on our slide several back, we read the $46 million. So the difference between his independently read review and ours is that you heard his cost and how he came up with per well plug-in cost and how we have come up with ours. So there was some differences there. Ours was a little lower, mostly because we have been incurring costs, and that's what we're using. His was based on a study of a lot more operators, service companies, and all that. But at the end of the day, ours was $46 million, his was $60 million; our balance sheet would be $136 million ARO, Randy's would be probably somewhere around $170 million.

And today, if you look at our balance sheet, there's just under $73 million today. So by the time you do this reevaluation and layer in the EQT, because as of the reporting date today, we don't have the EQT recorded. So that $72 million, looking to step up to about $140 million, inclusive of the enlarged portfolio.

Right. And so our $140 million, Randy's $170 million, EQT, CNX $190 million, or whatever, for just their [wheel] up. We just know that they're probably using way more cost, a very much shorter period of time, and probably a different discount rate. But we feel very good about our numbers. We know that our numbers are -- not only are accurate based on the cost and the longevity of the wells, but they have been through an audit and the auditors are comfortable with the numbers we're using also.

Yeah. When you think about the hands in which these previously sat, these are companies that are drilling wells that can cost anywhere from $5 million to $10 million to $15 million apiece. When you are plugging -- and the same companies have probably plugged 50 wells or less in a given year. That number just doesn't move their financials. It doesn't move the markets. No one really cares. Because everybody is focused on their drilling efficiency. So we have taken really a much more tailored approach to looking at this and tried to make -- give some reality to those numbers as opposed to just using a rough [slag] and a number that no one really thinks about. Well, that's what they do. Because we have a large portfolio, and we will be the hands that ultimately take these to the end of their lives based on the way that we operate our models.

So I hope that gives some context as to why there may be some variation in the way that one operator talks about the decommissioning liability versus the way that we do.

Thank you, all. Appreciate you showing up.