CONSOL Energy Inc. (NYSE:CNX)
Q4 2015 Results Earnings Conference Call
January 29, 2016 10:00 AM ET
Tyler Lewis - Vice President, IR
Nick DeIuliis - President and CEO
Dave Khani - Chief Financial Officer
Jim Grech - Chief Commercial Officer
Tim Dugan - COO, E&P Division
Neal Dingmann - SunTrust
Pavan Hoskote - Goldman Sachs
Evan Kurtz - Morgan Stanley
Holly Stewart - Howard Weil
Sameer Panjwani - Tudor, Pickering, Holt
Mathew Korn - Barclays
Jeffrey Campbell - Tuohy Brothers
Ladies and gentlemen, thank you for standing by and welcome to CONSOL Energy’s Fourth Quarter 2015 Conference Call Result. As a reminder, today’s call is being recorded. I would now like to turn the conference call over to the Vice President of Investor Relations, Mr. Tyler Lewis. Please go ahead, sir.
Thanks, John, and good morning, everybody. Welcome to CONSOL Energy’s fourth quarter conference call. We have in the room today Nick DeIuliis, our President and CEO; Dave Khani our Chief Financial Officer; Jim Grech, our Chief Commercial Officer; and Tim Dugan, our Chief Operating Officer of our E&P Division.
Today we’ll be discussing our fourth quarter results and we have posted slides to our website. As a reminder, any forward-looking statements we make or comments about future expectations are subject to business risk which we have laid out for you in our press release today as well as in previous SEC filings. We will begin our call today with prepared remarks by Nick, followed by Dave and then Tim. Jim Grech will then participate in the Q&A portion of the call.
With that, let me start the call with you, Nick.
Good morning. I’d like to kick things off with a quick recap of the macro environment in the industries in which CONSOL operates. Throughout the fourth quarter, natural gas prices fell by approximately 25%, oil declined approximately 15%, the BMA index for metals settled another $8 a metric ton lower and thermal coal storage is 9% above five-year averages. Over the course of the past year, the fourth public coal company recently filed for bankruptcy and the administration continued a politically driven assault on the production and utilization of coal. It’s truly an unprecedented time in every way, shape and form. Now even considering these issues in the coal market, CONSOL has accomplished in an extremely challenging environment, some pretty staggering things.
We’ve done this by managing what we can control, and specifically we’re talking about things like safety, unit costs, capital, capital spend, gas hedging and coal contracting. And I’d like to briefly touch on each one of these.
So, let’s start with safety. Safety, as most of you know is our core value and CONSOL had one of its best years ever in 2015, and especially when you look at severity level and safety performance. So zero incidents, zero accidents is our standard that means there is still more work to be done but we had a very good year in safety in 2015. And I applaud our employees especially when considering the onslaught of distractions that they’ve had to contend with throughout the year.
So whether it had to do with changes across the industry to be seen, share price performance, headcount reductions or you name it, there were plenty of distractions. I couldn’t be more proud of our employees for upholding our number one core value, throughout what’s been a challenging time across the industry that we operate within.
If you jump over to unit costs, unit costs for E&P and Coal have been consistently impressive. We met or exceeded all cost guidance that we provided over the past 18 months. Dave Khani and Tim Dugan are going to go in some more detail in a couple of minutes that CONSOL’s put some tremendous numbers in regards to cost improvements. For Coal, we’ve also done this while exerting production discipline and lowering our estimated 2016 sales tons. That might be very counterintuitive but it goes to show you that we push the status quo and we challenge our operators every day. This isn’t going to be an environment where we rest on our laurels. If you go over to gas hedging, throughout the year, we’ve layered in some substantial gas and basis hedges and we’re certainly glad that we did in hindsight. About two thirds of our gas production is hedged with NYMEX and basis hedges of $3.28 an Mcf. As protected revenue, it’s going to help derisk our business and internal free cash flow plan.
Jump over to capital discipline, really more importantly, capital efficiency improvement, so probably the biggest step changes we’ve seen in 2015. We’ve significantly reduced capital primarily due to efficiency improvements that we’ve seen around drilling, completions and especially cycle times. Our rate of change in cost improvements is industry leading, and Tim Dugan is going to expand on those details in a couple of minutes. We’ve gone from E&P capital spend level of a little over $800 million in 2015 to an estimated $205 million for 2016. Despite the reduction, we expect to grow gas volumes approximately 15% during the year, and we’re going to enter 2017 with around 60 drilled but unconcluded wells. We’ve been consistently reducing capital over the past year due to these efficiencies, debottlenecking improvements, and I believe we’re one of the first if not the first operators out there in terms of putting out an original 2016 budget. We’ll continue to benefit from capital efficiencies and production growth, will be a byproduct of making decisions based on things like rates of return and NAV per share.
Now, if we shift and talk a minute about contracted tons on the Coal segment side; if you’re a coal producer and you don’t have committed tons, you’re not going move your tons. Our committed tons quite frankly should be viewed as a premium in this market. That said, as we alluded to in our release and recent announcements lowering our estimated 2016 coal sales guidance as volatility is surrounding the timing of shipment due to high inventory levels of our customers. Now, we certainly value our customers and relationships with them, some of which span multiple decades. However, I want to be clear, our coal tons are sold, customers have a contractual obligation and our expectation is for them to stand behind our oral, written and legal requirements. We’ll continue to do our part by reducing cost as much as we can; we’re also focused on fighting for the top line at the same time.
All big levers that we focused on resulted in our leverage ratio at the end of the fourth quarter of 3.6 times which is a decrease from the prior quarter and was an obviously a continued degradation across the commodities throughout the quarter. In addition, CONSOL finished the fourth quarter with approximately negative $15 million of free cash flow. Now, if you remember, our target as we previously stated last quarter was to be free cash flow neutral. And we almost hit the goal but we know that almost isn’t good enough. That said, we do see this as a success, especially given the backdrop of the destruction [ph] we continue to see throughout the quarter in pricing highlighted in the opening remarks that I made.
Now, I’d like to just spend a minute or two addressing the topic of asset sales, which has been a recurring theme that has been prominent in our conversations with investors throughout the second half of 2015 in particular. Based on our base free cash flow plan, we don’t believe that we need to sell assets to support liquidity and our balance sheet. We’re going to remain patient and selective on what assets we’re willing to sell in this environment advantage. I think it’s important to remind people that we originally discussed our monetization program during our Analyst Day mid-year 2014. And starting then, we talked about having a bucket of valuable assets which we could potentially monetize over a number of years. And this was primarily driven to support our strategic transformation into a pure play Appalachian E&P company while at the same time potentially bringing forward values for assets that are no longer core to CONSOL.
Our suite of potential monetization candidates has changed since then and that’s predominantly a result of success that we’re seeing in the dry Utica Shale. We believe dry Utica adds substantial value to the company and where recent disclosures on our monetization program talk about running 30 processes and say that bids were coming in. We also said we’re running so many processes in order to create competition across these asset packages, and we’re not going to be afraid to pull things into the process or out of the process since we do not believe that we need to sell assets. So, despite the continued degradation across the commodities, we’ve completed five sales out of the 30 asset sale processes. In the third quarter last year, we posted about a $100 million of asset sales and we recently sold in the fourth quarter a mine in Utah to a private entity.
We’ve got a track record of success of selling assets. And when you look back starting in 2012 CONSOL has sold an aggregate $5.8 billion of assets, paid for in form of cash, royalty streams and the assumption of liabilities. We believe we’re positioned to ride out this environment. We’re not willing to sell assets at depressed prices based on our internal view of NAV per share, weighted against sale proceeds opportunities. Throughout the quarter, we saw that many of the potential counterparties are trying to use this environment against us. So, we’re still active and we’re taking a more patient approach being selective on what assets we sell and at what price. Nothing has changed regarding our strategy. We’ll continue to execute sales when we believe the timing is right. We believe we have the people, the assets and the balance sheet to write-off this environment.
So, in summary we don’t believe that we need to sell assets to support liquidity in our balance sheet. We’re going to remain patient; we’re going to remain selective on what assets we want to sell in this environment if any.
I just want to wrap up before I turn it over to Dave and Tim. Bottom-line is that we value growth when pricing is strong. When pricing is weak, strength of balance sheet becomes paramount. Again, we’re controlling what is within our power to control. Rules we made early on when prices began to deteriorate in 2014, those moves are paying dividends now and are going to continue to pay dividends in the future. We’ll continue to assess the environment we operate within and we act accordingly. We’ll make the prudent decisions necessary to ensure the balance sheet remains durable, and we’re going to ensure that we’re positioned to capitalize on opportunities when the markets turn, and the markets will turn.
With that now, I’m going to change things over to Dave Khani.
Thanks, Nick and good morning everyone. My comments will tie to our updated slide deck which is posted to our IR site under presentations to analysts. As highlighted in our press release this morning and indicated on slide five, CONSOL posted fourth quarter ‘15 adjusted EBITDA attributable to CONSOL Energy shareholders of $206 million. Cash flow from operations of $102 million and adjusted net loss of negative $0.26 or negative $0.11 per share.
There were a handful of adjustments during the quarter; specifically CONSOL again received a benefit of approximately $110 million resulting from recent retiree medical plan amendments. This benefit resulted in lower operating and other coal costs in the quarter as well as lower annual cash payments going forward related to these liabilities by about $15 million to $20 million.
In addition to the OPEB benefit, there were some additional items such as pension settlement expense, unrealized gain on commodity derivative instruments, gain on the sale of non-core assets, and $65 million tax valuation allowance. We have updated guidance for Coal, E&P and some corporate expense on slides 45 to 46, but first I want to applaud our teams that have demonstrated that they can exceed our forecast by reducing capital intensity and unit costs. We have world class assets and people managing them.
Now, looking over the E&P side; as stated on slide eight, E&P Division finished the quarter with a record production of 95.5 Bcfe and our average daily volumes now track above 1 Bcfe per day. As Tim will discuss in more detail, we have also announced the results of our second Pennsylvania dry Utica well in Green County which is very exciting. The combination of a small uplift in prices and cost reductions improved margins by about $0.51 per Mcfe sequentially. We realized $2.78 per Mcfe, which benefits from our hedge position and modest uptick in liquids prices. As you can see, we have above 60% of our E&P production hedge in 2016 along with our basis.
Now recently, basis has gone a little worse on our open volumes and this is reflected in our new guidance. We have approximately 300 million a day of open natural gas volumes at a current basis differential forecasted around $0.55 to $0.60 per Mcf. That said, on the E&P side, we are watching the impacts on low prices on activity. We’ve seen several producers head into bankruptcy, small and large producers cut CapEx by 40% to 60%, and un-hedged companies differing or shutting in production. I point this out because we expect to see supply response in 2016.
Now, on the cost side, we saw incredible cost performance, finishing the fourth quarter with total all-in and cash costs of $2.45 and $1.40 per Mcfe respectively. The cost performance is the combination of efficiency improvements and rising Marcellus and Utica shale volumes. Now, as we layer in dry Utica, unit cost reductions should continue well into 2017 and to 2020. With the much clearer picture of our cost into the future, we have stronger conviction to hedge profitability more in the outer years, stay tuned.
Now on capital, we recently brought down our E&P capital by another $185 million compared to the previous guidance of $400 million or $500 million. This is primarily driven by efficiencies that we are seeing across our E&P Division which is illustrated by our Marcellus D&C cost now around $1 million per 1,000 lateral feet. Midstream capital has come down meaningfully with its productivity improvements and stack pays.
Now to emphasize how much we’ve improved and to help you think through what 2017 volumes could be, I’ve some key details for you. For 2014 and 2015, we have spent about $1.5 billion of D&C capital. However, as of year-end 2015, we also have 102 gross DUCs and 42 wells fracked but not turned in volume. This has a net sum capital of about $421 million. So netting this out, we spent really $1.1 billion to double our production to about 1.04 Bcfe at year-end 2015 from the beginning of 2014. This production though has pressure constraints leading to large volume debottlenecking benefits that our CONE team will unlock.
Now, looking forward, we will all need to spend about $250 million to turn in line these 144 gross wells over the next couple of years. These wells have unconstrained net production of over 725 million cubic feet equivalent a day, enabling us to grow or offset 15% production decline in our underlying asset base.
Now, let’s move over to slide 10 on Coal. Our total Coal Division sold 6.6 million tons in the fourth quarter of 2015. The PA operations average sales price per ton decreased during quarter to $52.57 compared to $60.10 from a year-ago quarter in 2014. Northern App thermal coal prices saw continued declines due to consistently low regional natural gas prices, weak December weather and higher than normal inventory levels. This caused about 1 million tons of shipment deferrals that were replaced with some spot tons below our contracted price.
Our total coal cost for the quarter came in $41.97, reflecting all the work to drive down unit costs at our mines, including stream litigation. Our Buchanan Mine posted strong cost reduction sequentially and is likely the only met mine generating a profit in the United States at these low met price levels. Our PA complex was running at four days a week to manage the contract levels and will run below capacity until shipment pace increases to our contracted levels.
On the capital side, CONSOL’s Coal Division remains in maintenance of production capital mode and will focus on finding ways to reduce this capital in this environment.
Now, let’s move to slide 41, which highlights our balance sheet and liquidity position. CONSOL recently announced the reaffirmation of our $2 billion credit facility and maintains $856 million of liquidity, flat with the third quarter. Our leverage during the quarter, as Nick highlighted, came down sequentially to 3.6 times.
Now, last quarter, we detailed being free cash flow neutral with fourth quarter without asset sales. As Nick already highlighted, the commodity price environment got worse, particularly in December. Despite the E&P Division being free cash flow positive in the quarter, CNX in total was slightly shy of its free cash flow target by about $40 million when you exclude asset sales of about $28 million or about $15 million with asset sales. The $28 million was part of the $75 million to $125 million target that we announced back in July of 2015 when we announced our capital budget reduction. The impact from the weather on both commodity realizations and deferral of coal impacted cash flow by about $40 million in the quarter. However, looking forward, we have more than offset this by squeezing more costs and capital to derisk our free cash flow plan.
Now, our board has tied our 2016 short-term compensation for all middle managers and above to our free cash goals. So, this management team is very aligned with our overall goal to generate free cash flows to delever the balance sheet.
With our internal cash flow plan, we are confident that we can ride out this volatile market while positioning the company to capitalize on even a modest uptick in the commodity. Our confidence in our base free cash plan, solid liquidity and no maturities out for several years enables us to maintain our course and avoid the need to sell assets or tap the capital markets. Nick noted, we will sell assets and we will also drop down assets in one or both MLPs when appropriate.
So with that I’ll pass it over to Tim.
Thanks Dave. CONSOL continues to make great strides on E&P front. And today, I’d like to talk about significant improvements to-date, the accelerated rate of that improvement and most importantly the exciting growth potential we see in our business going forward.
In early 2014, we reorganized our E&P Division and cross functionally integrated asset teams. While this change was challenging initially, the new structure provided an increased focus that has really borne fruit and is repeatedly driving improvements in our E&P business. This is a primary driver behind our continued organic growth at lower cost and increased efficiency. This renewed focus was a point of emphasis at our analyst day in June of 2014 where we unveiled our plans to grow the E&P business with specific goals for improvement through 2016. I’m happy to say that we have met or exceeded the targets discussed at that analyst day.
We targeted a 5% to 10% annual reduction in operating expenses from 2014 through 2016. We sit here today in the beginning of 2016 with operating cost approximately 25% below where we started in 2014, and our efforts on this front will continue. Operationally, we’ve been focused on implementing lean manufacturing techniques, the impact of which can be seen in our drilling operations where horizontal drilling days have been reduced 29% from 14 days in 2014 to 10 days in 2015. Over the same period of time, our rig move day decreased 27% from 11 days to 8 days.
We’ve achieved 24-hour drilling footages in excess of 1 mile several times in last two years with the longest being 6,118 feet. Footage drilled per day is a key drilling metric and has improved 22% from 2014 and approximately 83% from 2013. Applying lean manufacturing techniques, data mining and rapid adoption of industry best practices has reduced CONSOL’s average operated Marcellus CapEx for 1,000 feet of lateral to less than $1 million today with projections for another 25% reduction over 2015. In addition to reducing cost and improving operational efficiencies, well quality improvements have driven our growth as well. And we remain on track to achieve approximately 30% compounded annual production growth rate from 2013 through 2016.
Now, that’s where we’ve come from; let’s talk about where we’re going.
In this morning’s press release, we detailed additional results in our dry Utica and the continued strong results demonstrated by wells previously brought on line. While still early, trends are beginning to emerge, and the new results and data coming in are exceeding our expectations, giving us greater confidence in the dry Utica’s potential and the opportunity it represents to drive dynamic growth in the company in the relatively near future. Our evaluation of the dry Utica is driven by four main variables: One, geology and reservoir characteristics; two, production and flow back methodology; three, drilling costs; and the fourth, our acreage and infrastructure position, specifically the advantages of our high NRIs and dry gas gathering infrastructure.
As a result of CONSOL’s large legacy land position in the Appalachian Basin, the company not only has an extensive acreage position of 600,000 plus net acres in the Utica but also a large and robust data set of Utica wells, enabling the company to move quickly up the learning curve. CONSOL has production results not only from the seven Utica wells now on line across the acreage but also from another 12 to 13 deep dry Utica wells where the company owns either a working interest or royalty, giving CONSOL what is likely the largest well control data set in the deep dry Utica. This well control data set now extends from Belmont county in Southeast Ohio through West Virginia into Southwest, PA and up through Westmoreland county, PA.
The attractiveness of the Utica lies in its present value opportunity, as we believe the over-pressured Utica rock has the potential to dramatically accelerate production volumes and therefore cash flows in the initial life of the well. While the benefits of the improved EURs from a managed pressure drawdown program in the Utica are already becoming well established, greater understanding of the rock spaces [ph] distribution and natural fracture characteristics is needed to further define our completion methodologies and will determine how hard operators can pull on the well in the early stages of its life without causing material damages to the wellbore ore formation.
In practice, we have already seen results from the Utica that support the expectation of sustained upfront production, based on our Gaut 4H testing as well as other mature production. We conservatively believe that we can hold Ohio production rates at 15 million to 20 million cubic feet per day for 9 to 12 months before they start to decline, with potentially even higher sustained production rates in Pennsylvania of 20 million to 30 million cubic feet per day or possibly higher.
With longer production history and additional well control, we’ll able to zero-in on the optimal rate at time periods that we can hold production flat. Pinpointing an optimized pressure drawdown pace subsequently helps us optimize our completion methodologies and the type of proppant and ploy. [Ph] As the greater the ability to pull hard down a well without embedment or damage to the wellbore or reservoir, the greater the rewards to use higher strength, the correspondingly higher cost profits. We are performing comprehensive completion modeling to determine the optimal design. These stimulations combined with economic evaluation will allow us to enhance rates of return.
On a drilling front, similar to early Marcellus drilling, the deep dry Utica has a learning curve. We are highly confident in our ability to lower drilling and completion costs in the dry Utica, not only due to our prior success and doing so in the Marcellus and wet Utica but also because of our early successes in Monroe County with the five dry Utica wells we drilled there last year. Our first Monroe County well came in with the drilling cost of roughly $9 million and took 84 days to drill. By our fifth well, we drilled this for under $5 million in first drilling days. We believe through an increased understanding of geo-mechanics and further bottom hole assembly and mud program optimizations, we can get that cost down under $4 million and 23 drilling days. We expect the same level of cost improvement in rest of our dry Utica areas.
In the Pennsylvania dry Utica, just eliminating the cost of science work conducted on the initial wells and the corresponding higher cost associated with non-productive time will generate $3 million to $4 million in savings for well. That combined with efficiency gains is over $9 million in CapEx savings and there is much more to come. Arguably the most important differentiating factor in terms of CONSOL’s present value and rates of return in the Utica is the company’s large legacy land position from its 150 plus years in business. This gives CONSOL a significant competitive advantage in terms of the number of acres controlled and fee or with low royalties, which increases NRIs and therefore boosts rates of return.
Keep in mind CONSOL owns a 100% working interest in our dry Utica acreage. In Southwestern PA, we expect our next 75 Utica laterals to have NRIs in the mid-90s while our competitors are happy to be reaching NRIs in the mid-80s. Furthermore, these wells will also benefit from the CONE gathering system in Southwest PA but has already built out for the dry gas Marcellus, lowering gathering costs and the necessary capital investment in production facilities. This represents a significant advantage to CONSOL compared to those operators that didn’t place gathering systems configured for wet gas. They will need to spend additional capital to build out dry gathering infrastructure, be disadvantaged on gathering costs by paying to process dry gas volumes or will have higher rates to compensate third party midstream companies for the cost of building out new dry gas gathering infrastructure.
While still early, continuously improving production results and a growing data set has recently led us to further increase our average EUR expectations. We’ve increased our EURs in the Ohio dry Utica from 2.4 Bcf per 1000 feet to 2.8 Bcf per 1000 foot of lateral. In the Pennsylvania dry Utica, we have increased EURs from 2.4 Bcf per 1000 foot of lateral to 3.0 Bcf per 1000 foot of lateral. As we continue to evaluate the data behind the Southwest PA type curves, it is likely that the data will support yet another increase in type curves. If we were to run the Southwest PA breakeven at 4.3 Bcf per 1000 foot of laterals, similar to our competitors, our breakeven price to achieve a 15% a tax rate of return would be less than a $1.65. As we drive our CapEx below the $15 million mark, these breakeven prices go even lower. Those breakeven prices are CONSOL specific at our advantaged high NRIs but when we run at the low -- run them at the lower average NRIs of our peers and all else being equal, we expect other operators will have higher breakeven prices.
An important point to address about the emerging Utica play is the fear in the market regarding the Utica’s impact on gas prices. These fears seemingly assume a static environment for all other natural gas development and the growing Utica volumes being additive to volumes from other plays, including the Marcellus. However, with production volumes across the U.S. declining, we expect dry Utica volumes will displace less economically advantaged production from other place, and dry Utica producers will be able to achieve attractive rates of return, even at lower commodity price levels will further benefit from capturing market share.
To close, despite being at a challenging point in the commodity price cycle, CONSOL remains firmly on track to achieve its goal to strongly grow the E&P businesses while reducing costs and lowering leverage. We continue to ring out the capital intensity for our E&P business. The capital required generate an incremental Mcfe of production has come down by 44% over the two-year period from 2013 to 2015 and is expected to increase even further in 2016. The continued performance of our wells has enabled us to achieve results with significantly less wells than previously expected. With 67 horizontal wells planned to be turned inline 2016 versus 130 in 2015 and 176 in 2014.
Our inventory of 42 completed wells that have not turned inline and 102 drilled uncompleted wells, we expect to exit 2017 with 77 drilled but uncompleted wells which will contribute to lower required capital intensity to maintain or grow production volumes. Our DUC inventory, continued efficiency improvements in the Marcellus and now the potential of the emerging dry Utica will sustain strong debt adjusted growth rates in our E&P Division going forward.
With that I will turn it back to Tyler.
Thanks Tim. And John, if you could open the call now for Q&A?
[Operator Instructions] And first line of Neal Dingmann with SunTrust. Please go ahead.
Nick, for you or Dave, and I don’t want to get too far ahead of myself, as you guys obviously now are sort of certainly appearing to be turning the corner on the free cash flow and I know as well as the liquidity. When you guys look ahead, I understand the plan this year as far as just knocking out those prior drilled wells, at some point what I am getting at is obviously given where you bonds seems to be trading a bit unrealistic, how do you -- and Dave, even you guys are looking at this -- look, let’s say even in 2017 or further between buying back the bonds, new drilling when you kind of look at just overall strategy?
We will -- without getting too particular in details of where we would put the dollars, just know we will do it probably in three buckets. It would go to essentially pay down our revolver, buyback our debt at a discount and/or start to layer in activities said into the dry Utica. I think those are the three areas. And it will be a function of how much free cash flow we generate and the relative rates of return between buying back our debt and drilling.
Okay. Go ahead.
And I think the rates of return that Tim is talking about, we are getting more and more confident on and obviously we set a sort of a timetable of mid-year of this year to before when we do make announcement of what we would do of our capital budget.
Makes sense. And then moving over that I was going to hit that part that Tim was addressing. How do you guys think about in this environment the completion cost? Obviously things such as -- it was nice to see those, dissolvable plug; I think that was few hundred-thousand you were able to save there. Nick, either for you or Tim, number one, what are you assuming for completion costs today; how does that compare since you are not drilling new wells today? And then are there other things like this -- things like the dissolvable plug and different things that could knock out a couple of hundred thousand dollars going forward?
I think the dissolvable plugs, as we showed on our recent Utica completions, shown considerable savings. That’s probably the most recent significant step, if you take market conditions out of the picture. The dissolvable plugs will become a standard. We were able to reduce several days off of our drill out and we were able to save about $0.25 million per well with those. But service costs have certainly come down and been a part of our savings. And we evaluate every well or how we choose to complete. We relook at our service costs because they are changing so quickly. So, we can take advantage there as much we can. I think there in this environment, we are not sure where the bottom is but they have come down significantly, and we do our best to stay on top of that.
And Tim, with these wells, how are you thinking about continuing with more extended laterals? I don’t know if you have done real done out. [Ph] I know there has been a couple out in the play 10,000ish. I mean, what your thoughts as far as where you think economic wise make sense in this environment or really in any environment I guess?
I think with technology and completion techniques, we continue to improve. We drilled over 10,000 foot lateral in Monroe County, Ohio and were able to successfully complete it. It has really come down to with the dry Utica, the completion practices, can you initiate the stimulation of fracture in these longer laterals. Right now, the Pennsylvania dry Utica at about 13,500 feet; that limit is somewhere around 7,000 feet. So that’s probably the limiting factor on lateral lines, as you go eastward and they get a little -- or westward and they get a little shallower that length is extended. So, it’s more of a pressure and technical limitation than it is economic. I mean the longer the laterals that -- lateral is the cheapest part of the well to drill. So, if we can drill longer laterals, we’ll certainly take advantage of that.
Our next question is from Pavan Hoskote with Goldman Sachs. Please go ahead.
So, you now have data from about 20 dry Utica wells drilled across Pennsylvania, Ohio and West Virginia, and we also have a lot more industry data points. So, as you start to put it all together, what parts of your Marcellus and Utica acres do you most the most confidence, both in terms about productivity as well as acreage prospectivity? And then if you rim [ph] development mode cost, where do you see well level breakevens and IRRs in these different areas?
Well, I think our largest data set -- the largest data set that we operate and control is in Southeast Ohio and Monroe County, so we have a high degree of confidence there with what we’ve been seen from a production standpoint but also what we’ve seen from improvements, operational improvements and our drilling and completion practices. But as I said in my remarks, the results that we’ve seen in Southwest PA continue to exceed our expectations. So, our confidence level across the Utica grows every day.
From a rate of return standpoint, breakeven prices with the Pennsylvania, Utica wells, we’re targeting $12.5 million to $15 million per well, at $15 million assuming the 95% NRI which is higher than other operators, our breakeven price is around a $1.85, to achieve a 15% rate of return. If we get that -- I’m sorry, it’s $2.11 at the $15 million mark. If we get that down to $12.5 million, it drops to about a $1.85. Southeast Ohio where the wells are a little bit shallower, we’ve already shown that we can get our cost down around $10 million mark, the breakeven price there is going to be a little over $2.
And so my follow-up to that would be that you have a lot of good quality acreage that seems breakeven between $1.85 and $2, for which you’re not getting a lot of credit. Now, at the same time, investors are placing a pretty heavy premium on leverage and liquidity. I fully understand your earlier comments that you do not need to sell assets, but would you consider divesting some of these high quality Marcellus and Utica acreage; is that an option at all?
Pavan, when it comes to the asset sales, we do point out that we do not need to do it because we are free cash flow positive, so. But we are actively marketing, in some cases negotiating a bunch of packages that will impact some potential acreage and E&P acreage, so it can impact Marcellus or Utica and maybe some of the other areas. But again, I want to point out, given our free cash flow plan, we will be very disciplined and really only complete transactions that create value for our shareholders. And that does take into consideration where our debt trades at. So, we will always make sure that we’re thinking about the rate of return for the use of proceeds as well. And we have consummated about a 100 million of proceeds so far. And as Nick pointed out we have done 5 billion since 2012. So, we’re not shy in selling assets. So, it’s just -- the markets right now are difficult and we’re going to be very patient and selective when we do so.
And then on an unrelated point, in your prepared remarks you talked about high coal inventories leading to coal shipment delays. Two questions on that. I understand that ultimately the buyers are obligated to take those volumes, but do you think there’s risk to further 2017 contracts -- risk that you’ve been able to find for the contract for the next six months for 2017? And then secondly what do you see as the impact on local gas pricing because of the weak coal markets?
Pavan, on the question about 2017, we’ve actually started being engaged with our customers for coal contracting in 2017 and ‘18 and actually beyond that. Our position for 2017, we have a great start on that right now at 61% contracted for our Pennsylvania operations. And some of the tons that we do get shifted out from 2016 into 2017 will add to that percentage sold. So, we’re looking at 2017 as we’re about two thirds sold already. And we do believe that the inventory levels will lead to a constricted spot market for the first three to six months of this year but we think as we get later in the year for the customers that we are contracted with, the customers that the power plants that have best capacity factors as the coal plants in the United States, their inventories will come down through the year and will be purchases by them in 2017. And I can’t say that’s true for all coal plants across the country but the ones that we’re dealing with the strong capacity factors that they have, they will get their inventories back under control, and they will be purchasing for 2017.
The other question you had on impact of coal prices on local gas prices. I’ve never seen that correlation as really been the other way around; the gas prices have had an effect on the coal prices. And as we see the forward strip in contango with the price increasing here over this year and next year, we think that in turn will get some headroom in the coal prices and allow them to rise as well.
Next is from Evan Kurtz with Morgan Stanley. Please go ahead.
Just a couple of questions on liquidity, I guess first, what are your thoughts on just tapping capital markets and putting the whole liquidity issue to bed once and for all?
Right now with our internal free cash flow plan, we are confident that we can ride out this volatile market. So, the capital market is very expensive. And so again we’re confident in our base free capital plan and we have 850 million of liquidity already and no maturities. So, going and try to tapping to this expensive capital market doesn’t make a lot of sense.
And then just one on dropdowns; what kind of signpost should we look for, or are you looking for rather as far as moving forward with further dropdowns I guess in terms of multiples or just commodity market conditions?
Obviously, the dropdowns have to make sense from both the sponsor as well as the MLP. And that would pertain either to CNXC or CNNX. And so it has to be accretive to CNXC or CNNX and it has to also be value added to us as the sponsor. So, we look at both things. And we want to make sure that when we go through the process, it’s both marks.
And we’ll go to Holly Stewart with Howard Weil. Please go ahead.
Just a couple of quick follow-ups, first on the D&C cost outline. Can you kind of walk us through both ends, kind of the high end and then a low end of the range?
Are you talking about the capital for 2016?
Yes, 2016 D&C?
Yes. So, where would we incrementally spend capital above is sort $205 million, that’s in our base plan now.
I think if the market dictates, we’ve got the flexibility to spend some additional capital on dry Utica. We could also accelerate some of our DUC inventory and complete some of those. But if we were to drill, it’d be probably dry Utica in Monroe County. But first option would be to further work down our DUC inventory and get those wells and mines, because that’s going to be the highest rate of return projects we have.
So, the high end of that range does include drilling a dry Utica well?
And then Tim, maybe just on the well cost of the dry Utica, can you outline kind of where we’ve gone from I guess the first Westmoreland well to the GH 9 and then any detail on the Marshall County well? I know you’ve mentioned 9 million in efficiency gains; if you can just kind of talk us through that 9 million?
Well that’s really looking at what we did in Monroe County, the gains that we saw over the first five wells in Monroe County, the efficiency gains. We expect to see those same efficiency improvements in Pennsylvania as we drill more deep wells there. So, we think there’s a significant savings there very easily another $4 million or $5 million just in efficiency improvements. And then taking out the non-productive time and the science work, that’s where that $9 million that I referred to comes from. And then when you look -- when you look, we’re already I think ahead of the curve when you compare what we have done to what our peers have done, when you consider the lateral lengths that we’ve drilled. GH 9 was over 6,100 feet; our peers were generally drilling 3,000 to 4,000 foot laterals and their costs -- some of them were several million dollars higher than ours. GH 9 will come in about $27 million. So, you take that $9 million off there, we’re already fairly close to our $15 million target. And we think that as we drill more wells, the continued efficiencies will come quickly. And we’ll get to that $15 million range within handful wells.
On the completion side, we will continue to evaluate that. In some areas, there may be a need to spend more money on completions. We may be able to cut those costs. We’re using high cost proppants, we’re using ceramic proppants. We think as those become more widely used, the cost of those will come down. So, we’ve got some evaluation and data to collect on the completion but we don’t want to push the cost down too quickly until we have a good understanding of what we need to do to enhance our EURs.
Is there a target on a per lateral foot basis that you’re trying to get to?
Well, the target we’ve used in Pennsylvania is $12.5 million to $15 million; we think we can get to $15 million fairly quickly. And then, we’ll work it down over the course of the next year or so to $12.5 million. Our average lateral lengths in Pennsylvania have been around 6,000 feet. So that comes out to $2 million per 1,000 foot of lateral. And that will work its way down over time, continue to improve. And then in Ohio, we’ve set a $10 million target for the Ohio dry Utica.
And then just one follow-up, maybe for Jim. On the NGL realizations during the quarter, I mean a nice move up versus last quarter as well as compensate, just curious if there is anything abnormal kind of going on there. I know you saw a little bit of increase in NGL prices during the quarter but does it seem like enough to warrant the big percentage to move up, so just kind of curious as to anything there?
Holly, a lot of it has to do with two things, one the seasonality and the prices jumping in the fourth quarter; and two, the mix of our NGLs, we had -- about half of it was propane, and propane went from $0.07 or $0.08 a gallon up to $0.35 a gallon. So, the seasonality and the mix in the propane in that mix led to the higher realizations. Now, at the end of this quarter here, we do expect to start exporting ethane with the INEOS contract, and that would we think further bump our ethane realizations but that wouldn’t have had effect obviously on the fourth quarter; it’s going to have effect here at the end of the first quarter.
Our next question is from Sameer Panjwani with Tudor, Pickering, Holt. Please go ahead.
I appreciate the color on the cost of that GH 9 well. I was looking for some more color on the ops front in terms of rate of change when it comes to drilling days between the Gaut and GH9?
I believe we were up around 100 days on GH 9; I don’t have that exact number, I could get that for you but it was certainly an improvement over the Guat. With both -- as we have said in the past, the most challenging part of the drilling operations in the deep Utica wells is drilling the vertical section, getting down through the Salina, [ph] getting -- we have to set almost 12,500 feet of 9-5/8 inch casing. So, we’re drilling 12.25-inch hole for 12,000 feet. And that is by far the most challenging part of the hole. We expect -- we’ve got to get that down to roughly 50 days; this is what our target is. And that’s in line with that $12.5 million to $15 million total well cost target that we have. But both the first two wells we had planned on longer drilling times, we knew we had to work through some of the learnings, and I think we’ve done that. We’ve got some -- a lot of data, not just production data but with all the other wells we have interest in; we have information on drilling of -- and operations for quite a few wells. And that will help us get down to that 50-day target.
So, I guess is it fair to assume that for the entire length of a lateral and the vertical and the completion to be about 60 to 65 days is what you have baked into that in that budget that you stated?
Okay. And then just last question from me. So current well costs and current pricing, I guess as current well costs, what do you think the economics are at current pricing and also what’s the breakeven?
Well, at current pricing, when we talk about breakevens, we’re really focused on the target costs that we’re working towards. I don’t have a breakeven cost that the $26 million or $27 million that we spent on those first two wells. We knew going into it we were going to spend more money on those first couple of wells with science and some of the learnings that we had to go through. As I mentioned, the breakeven price when we hit our target -- at $15 million, our breakeven price is $2.11 and we if get it down to $12.5 million, it will be down around to $1.85.
Okay, great. Thank you for the color.
We expect to get there fairly quickly in the next handful wells.
And next we go to Mathew Korn with Barclays. Please go ahead.
Stepping back a bit, is there any sign or even early developing worries on future supply, even the gas side or the coal side among your buyers? By that I mean do you see the reduced drilling activity, the rig counts, or just CapEx, the coal mine shutdowns et cetera, et cetera; is there any concern we’re going to wake up in the morning in mid ‘17 and the futures curve is going to be a lot higher than where it is now?
On the coal market, supply side, we’ve been sort of heading on this theme for it seems like probably a span of three quarters now. There are permanent substantial shifts that are occurring and we’re seeing these in every basin in United States and as you can see the data quarter-on-quarter sequentially annually. The numbers that we’ve seen most recently, just about every basin seems to be down 30%. But more importantly behind those reductions in production numbers are again permanent closures of finding supply sources. We’ve seen it in Northern Appalachia over the past number of months. It’s certain locations that have been supplying Northern Appalachian coal to the markets for decades. And you’ve obviously been seeing it in Central Appalachia; you’re seeing it in the Illinois basin in a major way. And our view is based on the government’s talking about, you’re going to see that maybe across the board, the Powder River basin. So there’s been a permanent significant shift on the coal side, the supply but Jim Grech has some additional color on that and also the E&P side.
Yes Matthew, I’ll start with the coal where Nick left off. The customers, the buyers on the coal side are expressing a lot of concern about the reliability of supply from domestic producers. The financial strength of CONSOL is one of the things that stands out along with the strength of our reserve base as we’re out contracting. And some numbers to back up what’s going on with that is we’re taking much more domestic contracts and sales this year than we have in previous years, as customers are -- the domestic market actually is expanding for us. For example, last year in the export markets, we had about 5.3 million tons of export coal from our Bailey complex. This year we’re going to have about 1.5 million tons and almost all of that’s metallurgical coal not thermal coal. And part of that is with the production numbers but the overwhelming majority of that is us getting into new markets domestically because the customers are worried about the reliability of supply. We are selling coal in the upper Midwest; we’re selling coal in the river systems again and we’re selling coal down in the southeast, the markets that are geographically the farthest away from us. And one of the reasons we’re doing that is because the customers concern about supply and they want diversification in their supply base and they look around at who’s going to be here in the coming years in the coal space, and CONSOL certainly stands out.
The same type of concerns, I won’t say are as deep or as spread out in the gas side but we are starting to hear them from the customers on the gas side and maybe more importantly from the pipelines who want you to enter in the long term commitments, so looking at the financial stability in the E&P space. I think it’s going to be there to fulfill their FT commitments on these pipes who’s going to be able to be there five years, ten years, 15 years from now. Again, I’d say those concerns are there. They’re not as rampant as they’re in the coal space but we do start -- we are starting to hear that from the customer base the concerns about the E&P side, financial stability of the producers, and again CONSOL comes out really well in comparison with our peers in those types of metrics.
Thanks, it’s very helpful color. We’re getting -- particularly in the coal side, of course we’re getting fewer and fewer windows to how the market’s actually behaving. Maybe follow-up, just quickly regarding Buchanan. The aim is there to add more domestic sales to [indiscernible] towards more the domestic market, steel mill capacity here in the States is down in the mid 60s, we’ve seen some mill closures over the past several months. Have you seen any kind of noticeable loosening of that domestic market, and counter to that have the bankruptcies we’ve seen like Walter, have they had any effect in that market as of yet?
Matthew, statistically, again I’ll give you some numbers on that. Buchanan, this year, about 20% of the -- I mean last year 2015, about 20% of the coal stayed domestic. And in 2016, we’re going to have similar production numbers. And we think at least 40% if not more of that coal will be in the domestic markets. And we’re contracting for that already or have that under contract. So, same dynamic as the thermal markets, the metallurgical market in the U.S., there’s concern about the financial stability on the supply side, and we’re taking advantage of that and we’ve doubled our domestic sale for Buchanan in 2016 over 2015.
And next we go to Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Good morning and I share the congratulations on the cost improvements. First, I want to ask, pulling together your remarks today, going forward, are we to assume that the dry Utica is the first zone of choice once capital is allocated to drilling again? And if so, does this mean the Utica exclusively on existing pads or can the Utica become the first zone on new pads?
It provides us with additional flexibility and optionality. We certainly have -- we’ve got to get to get to our goals of $12.5 million to $15 million. And as I said, we expect to do that over the next handful of wells. So, I would expect in the next year or two that Utica’s going to continually become a larger and larger part of our development program and our growth. It certainly doesn’t completely push the Marcellus aside. The Marcellus will continue to be a big part of our growth strategy but the Utica will play a bigger and bigger role as we move into ‘17 and ‘18.
And remember, we want to share the infrastructure, and so we really like to hit both zones, and maximize the rate of return.
And I’ll turn it back to the presenters for any closing comments.
Great, thanks John. That concludes our fourth quarter earnings call. Thank you everyone for joining today’s call. John, if you could please review the details for the replay information.
Certainly. Ladies and gentlemen, this conference is available for replay. It starts today at 12:30 p.m. Eastern, will last until February 5th at midnight. You may access the replay at any time by dialing 800-475-6701 or 320-365-3844, the access code is 375020. Those numbers again, 800-475-6701 or 320-365-3844 and the access code, 375020. That does conclude your conference for today. Thank you for your participation. You may now disconnect.
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