Alliance Resource Partners LP (ARLP) 2014 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2014 Alliance Resource Partners and Alliance Holdings GP Earnings Conference Call. My name is Jackie, and I will be your coordinator for today. At this time, all participants are in a listen-only mode, and we will be facilitating a question-and-answer session towards the end of today's presentation.

(Operator Instructions)

I would now like to turn the presentation over to Mr. Brian Cantrell, Senior Vice President and Chief Financial Officer. Please proceed, sir.

Thank you Jackie, and welcome everyone. Earlier this morning we released 2014 fourth-quarter earnings for both Alliance Resource Partners, or ARLP, and Alliance Holdings GP, or AHGP. We'll now discuss these results, as well as our outlook for 2015. Following our prepared remarks, we'll open the call to your questions.

Before we begin, a reminder that some of our remarks may include forward-looking statements that are subject to a variety of risks, uncertainties, and assumptions which are contained in our filings from time to time with the Securities and Exchange Commission, and are also reflected in today's press releases.

While these forward-looking statements are based on information currently available to us, if one or more of these risks or uncertainties materialize, or if our underlying assumptions prove incorrect, actual results may vary materially from those we projected or expected. In providing these remarks, neither partnership has any obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, or otherwise.

Finally, we'll also be discussing certain non-GAAP financial measures. Definitions and reconciliations of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures are contained at the end of the ARLP press release, which has been posted on ARLP's website and furnished to the SEC on Form 8-K.

Now that we're through the required preliminaries, I'll turn the call over to Joe Craft, our President and Chief Executive Officer. Joe?

Thank you, Brian. Good morning, everyone. This morning, ARLP reported new annual operating and financial milestones, the 14th consecutive year of record performance. ARLP finished the year strong, posting increases to quarterly coal sales and production volumes and revenues. These results, combined with lower per-ton operating costs to drive ARLP's EBITDA higher by 15.1% over the 2013 quarter, while net income also increased 24.6% compared to the same period.

For the 2014 year, increased coal sales and production volumes, strong pricing, and lower costs were the primary factors for our 17.2% improvement in EBITDA, and 26.4% growth in net income. ARLP's operations delivered the highest production output in our history, as total coal production grew 5.1% in 2014 compared to 2013.

The performance at Tunnel Ridge was particularly notable. Year-over-year production at the mine increased nearly 2.6 million tons, helping to drive segment-adjusted EBITDA expense lower by $10.45 per ton in our Appalachia region.

Volumes were also higher in the Illinois Basin, as production at Dotiki increased 12.7% over the prior year, and our new Gibson South mine added approximately 840,000 tons to production in 2014. The increased volumes and other cost-control measures helped to reduce our segment-adjusted EBITDA expense per ton by 3.4% in 2014.

ARLP's marketing team also performed well during arguably one of the most challenging coal markets in recent memory, selling more tons in 2014 at higher average prices than at any time in our history, and driving revenues to an all-time high of $2.3 billion. Through their efforts, ARLP further strengthened its long-term coal sales position in 2014 by securing new commitments for the delivery of approximately 30.2 million tons through 2018.

ARLP enters 2015 with approximately 39.3 million tons, or 92.6%, at the midpoint of our estimated coal sales volume, contractually committed in price for this year, and 28.9 million tons priced and committed for 2016. As we celebrate our past success, ARLP also remains focused on our future. The transactions we announced today, growing our total reserve base by 50% to 1.6 billion tons, represent significant steps in securing our position as a low-cost preferred provider to the markets we serve for many years to come.

The reserves acquired are of similar quality as our River View mine, enjoying similar cost and transportation advantages compared to our competitors. These acquisitions not only substantially increase our coal reserves, they also provide ARLP with the flexibility to efficiently extend and expand existing operations, and the opportunity to strategically develop new organic growth prospects in the future.

While ARLP remains committed to building on its successful coal platform, we also saw an opportunity to take a modest step toward expanding our base by investing in US oil and gas mineral interests. Although our current commitment to this activity is relatively small, we are hopeful that this investment could develop into another growth platform, and be complimentary to ARLP's strategy of increasing unit holder distributions through sustainable growth in cash flow.

Entering 2015, the coal industry clearly continues to face significant challenges. As we look forward, however, we continue to believe that ARLP is well positioned to successfully navigate these challenges, and are confident that our strategy will continue to drive long-term value for our unit holders.

Reflecting on our record performance and commitment to the future, Alliance's Boards approved increased unit holder distributions for the 27th consecutive quarter, bringing our year-over-year distribution growth to 8.6% at ARLP, and 10.6% at AHGP. At this time, I'll turn the call back to Brian for a more detailed look at our financial results and guidance, after which we will open the call to answer your questions. Brian?

Thank you, Joe. Looking first at our full-year results, as Joe just mentioned, ARLP once again posted new annual records in 2014 for our major operating and financial metrics, led by higher volumes at our Tunnel Ridge and MC Mining operations in Appalachia, as well as added production from our new Gibson South mine, and strong performance at our Dotiki mine in the Illinois Basin, ARLP's operations delivered solid results, year-over-year coal production increasing approximately 2 million tons to 40.7 million tons, and total coal sales volumes climbing by approximately 900,000 tons to 39.7 million tons in 2014.

For the year, volume and pricing growth drove ARLP's revenues higher by 4.3% in 2014 to a record $2.3 billion. Increased volumes and revenues combined with lower operating costs to push ARLP's EBITDA and net income to new records in 2014, totaling $803.7 million and $497.2 million respectively. While we came into 2014 expecting per-ton results would be comparable to 2013, ARLP's per-ton metric also showed year-over-year improvement.

Better than anticipated performance at Tunnel Ridge resulted in a favorable sales mix to lead ARLP's annual average coal sales price slightly higher in 2014 compared to the prior year. Increased volumes at Tunnel Ridge also drove segment-adjusted EBITDA expense per ton in Appalachia lower by 20.8%, and contributed to lower consolidated operating expense in 2014, as well, with ARLP's total segment adjusted EBITDA expense dropping to $34.78 per ton, an improvement of $1.24 per ton compared to the prior year. Increased pricing and lower costs drove ARLP's 2014 segment-adjusted EBITDA higher by $2.75 per ton sold, or 14.2% compared to 2013.

Looking briefly at results for the 2014 quarter, as discussed during our last call, ARLP anticipated that our results could be impacted by transportation shortages we expected to persist through the end of the year. Our expectations proved to be accurate, as transportation challenges in October and November contributed to a 385,000-ton build in inventory during the 2014 quarter. Despite these transportation challenges, ARLP delivered strong performance during the 2014 quarter, posting increases for total coal sales and production volumes, revenues, EBITDA, and net income, compared to both the 2013 and sequential quarters.

Let's now turn to our initial guidance for 2015. Looking first at capital expenditures and investments, ARLP currently anticipates 2015 total capital expenditures in a range of $300 million to $330 million, including maintenance capital expenditures, and this compares to $311.5 million in 2014.

As noted in our release, these expenditures include $19 million to $29 million for the purchase of coal reserves, mining equipment, and underground infrastructure from Patriot; additional reserve acquisitions related to our participation in the White Oak mine Number 1; expansion of preparation plant capacity at the River View mine; and the purchase of additional equipment at our Gibson South mine.

Consistent with our approach of estimating maintenance capital over a long-term horizon due to the inherently cyclical nature of these expenditures, for our distribution planning purposes, ARLP is currently estimating total average maintenance capital expenditures of approximately $5.55 per ton produced over the next five years.

In addition to the capital expenditures just discussed, in 2015 ARLP also currently expects to fund equity investments of approximately $25 million to $30 million. Included in this total is an estimated $15 million to $20 million related to the previously discussed commitment to acquire oil and gas mineral interests.

Regarding ARLP's preferred equity commitment to White Oak, we currently anticipate our funding to this commitment in 2015 will be less than $10 million, down significantly from the approximately $99.8 million funded in 2014. In summary, ARLP currently anticipates total capital expenditures and equity investments in a range of $325 million to $360 million for 2015, well below its 2014 total of approximately $443.4 million.

Reflecting current market conditions, ARLP is estimating 2015 coal production in a range of 40.4 million to 42.5 million tons, or approximately 4 million tons below our installed capacity. This range reflects our plans to maintain the Gibson complex at its current operating level of six production units during 2015. We do anticipate that improved performance by transportation providers in 2015 will help us return ARLP's coal inventories to more normalized levels by the end of the year.

Reflecting this expectation and based on our current production estimates, coal sales volumes for 2015 are currently estimated in a range of 41.4 million to 43.5 million tons, of which approximately 39.3 million tons are priced and committed. Based on these existing commitments and expectations for filling its current open position, ARLP anticipates its average coal sales price per ton to be approximately 2% to 3% lower in 2015 compared to 2014.

Lower realizations in 2015 primarily reflect the impact of two factors. First, deteriorating market conditions for the low sulfur coals produced by the Gibson complex and MC Mining, and the customer breach of an above-market coal supply agreement, which is now in litigation. Increased coal sales volumes and additional other revenues from White Oak are expected to more than offset lower coal sales prices, resulting in 2015 revenues in a range of $2.39 billion to $2.48 billion, excluding transportation revenues, and this is approximately 6.8% higher at the mid-point compared to 2014.

For 2015, ARLP is currently expecting to generate EBITDA in a range of $765 million to $825 million, comparable to 2014 results at the mid-point. Net income for 2015 is estimated in a range of $395 million to $455 million. In analyzing ARLP's current guidance for EBITDA and net income, I think it would be helpful to elaborate on several factors which are expected to impact our results in 2015.

First, our current plans to operate at less than full capacity this year obviously affect our cost and margin expectations. In addition, we expect lower plant recoveries at MC Mining in 2015 compared to 2014. As a result, ARLP anticipates segment-adjusted EBITDA expense per ton will increase at the mid-point of our 2015 guidance by 4% to 5% compared to 2014, and this will drive realized margins per ton lower by 7% to 8%.

These expectations, combined with the impact of the contract breach we discussed a few minutes ago, caused ARLP to lower its initial 2015 estimates for EBITDA and net income below our previous expectations. Supply and demand dynamics continue to evolve, however, and our excess production capacity provides ARLP with the opportunity to quickly respond to any improvement in the coal markets, providing potential upside to our expectations for 2015 and beyond.

Second, compared to 2014, net income in 2015 is impacted by a $71.6 million increase in depreciation, depletion, and amortization. This increase is primarily due to the acceleration of depreciation at the Hopkins mine, increased production at the Gibson South mine, amortization of the acquisition costs of coal sales contracts purchased from Patriot, and increased DD&A attributable to our coal reserves and surface facilities related to our investments in White Oak.

Finally, on a positive note, with the White Oak mine number 1 long wall in production for a full year, ARLP anticipates increased coal royalties and throughput service revenues from White Oak will drive other revenues higher in 2015 by an estimated $75 million to $85 million, compared to $21.2 million related to White Oak in 2014.

Based on estimates from White Oak, ARLP's EBITDA is expected to benefit by approximately $30 million to $35 million in 2015, compared to a negative impact on 2014 EBITDA of $3.4 million. Net income related to White Oak is also expected to increase in 2015 to a range of $20 million to $30 million, compared to a loss of $5.7 million in 2014.

I'll close with a brief comment on our balance sheet. During the 2014 quarter, ARLP completed a receivable securitization facility, increasing our liquidity by an additional $100 million at an attractive cost of capital. We entered 2015 with total liquidity of approximately $579.2 million, our debt to EBITDA ratio at a conservative one times leverage, and a total distribution coverage of 1.72 times.

Our strong balance sheet should serve ARLP well in a difficult market, and provide us the financial flexibility to take advantage of opportunities that develop as we execute our strategy. This concludes our prepared comments, and now with Jackie's assistance, we'll open the call to your questions.

(Operator Instructions)

Your first question comes from the line of John Bridges with JPMorgan. Please proceed.

Good morning, Joe, Brian. Congratulations on the results. Mr. Market seems to like them. I see they're up again -- you're up a little bit this morning.

Thank you.

When did the -- I know it's small, but the investment in oil and gas, what's the logic behind that? I know you've spoken about looking at other sectors, but where would you like to see that developing? Where would you like to see that developing?

Right. We have been looking at other opportunities to invest our cash flow, and we've been -- we were fortunate to find this opportunity with an experienced and talented group of folks that have been in the land company business for several decades.

We're investing in a limited partnership. We'll have about 70% of that limited partnership. We are committing roughly $50 million to be invested over a two- to four-year time period, depending on the opportunity. We are hopeful that that will prove to be successful, and we can continue to make additional contributions in the future.

We believe that the US will be one of the top global producers of crude oil, and the prices that we are seeing today have provided a good opportunity, we believe, to make an investment, and be able to meet our return threshold. We're starting at a $50-million commitment level. If it proves to be successful, which we're optimistic it will, then we can continue to add to that as opportunities present themselves.

Where is this company active?

They are active in all basins. They will be looking at opportunities in all the major producing basins. I'm sure there will be a concentration on those basins that have opportunities for low-cost production, so that we can get the benefit of drilling activity as opportunities present themselves.

Okay. As a follow-up, I guess with the state of the market, you're getting some significant savings in your capital investment. I would imagine that you're not going direct to the original equipment manufacturer for some of the equipment you're looking for?

That's correct. There is opportunities to pick up used equipment. In addition to the Patriot opportunity, there are other opportunities for us to buy used equipment. That's one of the reasons why our maintenance CapEx number reduced a little bit this quarter compared to prior-quarter guidance.

Okay, great. Well done, guys. Congratulations.

Thank you.

Your next question comes from the line of Brian Yu with Citi. Please proceed.

Great, thanks. Congrats on a good quarter, guys. For your guidance on the revenues, and then actually more on a per-ton basis than cost, would you be able to break that down more Appalachia versus Illinois Basin, if there is material difference in the percentages?

I think that on the cost side, the increases are probably going to be a little bit more weighted to the Appalachia area, and really the revenue as well. We've got some -- as we look at the -- you can look at the NYMEX curve, for example, for low sulfur coal. It has dropped quite a bit.

That low price for low sulfur in the central Appalachia is transferring over to our low price -- or excuse me, our low sulfur coal at Gibson County. There will be some impact in Illinois Basin relative to the revenue side, but I would say that most of it's going to be on Appalachia side for both revenue and cost.

Okay. On this customer breach, can you give any more details on how many tons we're talking about, and then what those tons -- are they still taking it, or are you placing it with someone else?

They are -- the contract that is in dispute had a term going through 2020. The range of sales is anywhere from 700,000 to 800,000 a year. It varies year to year.

The allegation -- the utility is claiming its mercury, the MATS rule related. The impact will start in April, April 15, which is the effective date of the mercury rule.

As to the impact relative to damages, we're not in a position to talk about that today, since it is in litigation. But that's the range of the size of the sales that were impacted. We do continue to sell to that customer -- not necessarily back to back, but we are selling to that customer with other contracts, as well as selling to them in the spot market.

Got it. The last one on the transportation and inventory build, deal with what's happened in the oil and gas markets. Are you seeing service improve? With working down those inventories, is that something we can expect maybe in the first quarter or first half as opposed to second half, or would you expect that to be more evenly distributed throughout the year?

We have seen the transportation improve, particularly in December, and it's done better in January. As far as the pace, I think it will probably be throughout the year, as opposed to just being able to get the full benefit in the first quarter.

Some of that's driven by customer needs and expectations, as well as the transportation. We're not anticipating transportation to be a bottleneck in 2015. It's really going to be dependent on what the customers' needs are.

Okay, great. Thank you.

Your next question comes from the line of Sam Dubinski with Wells Fargo. Please proceed.

Great, guys. Thanks for taking my question, just a very high level. How much excess supply on a tonnage basis do you think there is in the Illinois Basin on a supply basis?

Then on the demand side, what do you think is the biggest lever going forward? Is it going to be the dollar strength in passing export markets for some of your competitors?

Is it weather? Is it natural gas? What do you think will be the biggest lever on the demand side to kind of tighten things up?

I think on the supply/demand for Illinois Basin, we think it's relatively -- it's closer to being in balance than what the markets are currently projecting. You'll know when you look at some of this excess capacity that we're pulling off that most of that is in Illinois Basin.

That's sort of the magnitude of that 4 million tons. We'd like to believe that's going to bring it back into balance.

It's hard to know what other people anticipate when they are looking at supply/demand, whether they were factoring us producing that or not, and how that plays into the market. But with Patriot reducing their production and us pulling, not producing 4 million that we were capable of producing into 2015, we think it's relatively close.

The demand side, on the other hand, I think natural gas prices are a factor. Weather is a factor. Exports are a factor. All three of those are factors.

As we look at the oil price decline, what that's going to do to natural gas supply, there's different views on whether that's going to be U-shaped or V-shaped and how fast supply will fall off on associated gas, for example. It's really hard to know, but I think that's a catalyst to the demand side for coal.

We are expecting to lose some market in 2015 relative to 2014 from gas to coal, or coal to gas switching. But our projections aren't quite as much as what Peabody said yesterday.

I think when we look at the amount of tonnage that's contracted by us and others, we don't believe it can drop that much unless utilities decide not to take the tons under the contracts. But as we look at demand going forward, it's gas-driven, it's export-driven, weather-driven, would be the three factors.

Great. I apologize, I think I just missed the answer, but what was the size of the contract that's in the customer breach? How big is that on a tonnage basis? What's the time frame for resolution? Is this multi-year?

The contract goes to 2020. The amount, the annual amount's anywhere from 700,00 to 800,000 tons a year.

Okay.

The customer has indicated they will stop taking that tonnage April 15 of 2015. So you can take April 15, 2015 to 2020, on that annual basis, and that will give you what the tonnage is.

Okay, and then on a resolution time frame?

We would expect the trial to be probably mid-year 2016. That's a guess. Don't know for sure.

Okay. I'm not a legal expert, but is there a chance that maybe damage could be trebled or things like that, for infringement, or would you recognize the life of the value of contract, if you want? How does this tend to work its way out in terms of what you're seeking?

Given the fact that it's in litigation, I'm not prepared to talk about the range of damages at this moment in time.

Okay, great. My last question, just on the cost side, are there any other levers -- let's pretend demand stays where it is. Are there any other levers to reduce costs or CapEx further than what you're guiding to today?

I think it's possible that -- one of the factors in our CapEx is we had $30 million worth of carry-over from 2014 into 2015. It's very possible we could see something of that magnitude again in 2015 to 2016 from a timing standpoint.

On the cost savings, there are some opportunities for some cost savings in these numbers. For example, we did not -- we're not a big diesel user because we're not a surface mine.

But at the same time, we do use enough that it's meaningful to where if the oil prices persisted in the $45 range, we could get savings of $5 million plus or minus on that factor that we did not include in these estimates. We did not assume a $45 oil price when we put our budget together. We were closer to probably $65 --

Okay.

When we put our plan together. There's some opportunity there. We're focused on cost control, so yes, I believe there's opportunity for us to do better than what we've got. We're just giving you our best guesstimate at this time.

Okay. Thank you very much. Good luck.

Thanks, Sam.

Your next question comes from the line of Paul Forward with Stifel. Please proceed.

I think, Joe, you had mentioned that $50 million that you're looking at and spending, or investing, on the oil and gas side of things, I wanted to -- but you've obviously also been active in picking up reserves.

Can you look at -- because we've seen energy prices, coal prices all come down -- can you describe right now the opportunity set as you see it as far as where the best acquisition values might be if you were to compare that investment in the oil and gas side to either what's available in coal in the Illinois Basin or coal outside the Illinois Basin? How do you approach the -- line up one opportunity against another, and come to a decision on how you might invest, outside of what your current operations?

One of the factors is we're looking for long-term stable cash flow. When we think in terms of, again, the US being a top global producer of oil, we saw that as an opportunity for us to invest in long-term assets that will provide opportunities for long-term cash flows, that will allow us to have a base to be able to have our sustainable growth. We see that very complementary to what we're doing, as an opportunity where we can pretty much predict what those returns are, and feel comfortable on a risk/reward basis, that it's a very attractive opportunity.

With our debt capacity where it is, we've got the opportunity to make several investments if we think that the -- in both the coal space, as well as the other midstream space, if we think the risk/reward presents itself to where it would be a solid, good, long-term investment for us.

As we look at the coal landscape -- and one of the drivers for us to do what we did, we were effectively doubling our reserves -- our past success has been primarily been driven by organic growth. We're fortunate that we were able to secure all these reserves right in our backyard, essentially putting together a very impressive block of coal contiguous with each other, gives us tremendous optionality and scale.

It does, as we look at how can you grow in the business, we felt like that was the best opportunity for us to have a low-cost entry of capital with low-cost reserves, with low-cost transportation. It just fit our model. We've had our eyes on these reserves for many years.

I think with the pressures of the coal business, the owners of these reserves decided that they would rather have the cash than hold on to it for themselves. The opportunity presented itself in 2014, 2015 for us to make that acquisition.

As we think beyond that, we'll continue to evaluate opportunities. I think that the criteria has to be a low-cost opportunity. They've got to have a low-cost reserve if we're going to look at an operation and/or another reserve play. It has to be a low-cost opportunity where we see that can have sustainable cash flow for a 10-year, say, time horizon, plus or minus. That's what we would be looking for.

Great. As you look at your newly acquired reserves, when you think about the timetable of actually going in and putting capital to work in developing them, I'm assuming it's a fairly long time frame for doing this, and you would need to have support from customer commitments to take that coal before you would really make significant investments. Is there any sort of time frame that you could look at as far as when you would anticipate going ahead and developing the newly acquired reserves?

In 2015 we did announce in this earnings release that we'll begin immediately to expand our preparation plant, the capacity at our preparation plant at River View. That will allow us to move three units of equipment from our Hawkins County mine that is depleting in early 2016.

We'll be moving those units and some people over in the early 2016 time frame that will allow us to immediately take advantage of some of this, where we will have the ability to effectively mine the same amount of tonnage that Hawkins County is mining today with four units, we'll mine with three units at River View. You'll see that cost differential going into 2016.

As we go forward, we've got our Patiki operation has a reserve life in the 2021, 2020 time frame. We can do the same thing there as we think through how you maintain market share as we have other reserves that are depleting, as opposed to doing other things that we had originally planned to sustain that market share and that EBITDA. We've got those opportunities. Now whether we can grow them beyond that, it's going to be totally driven by depletion, or excuse me -- well, depletion by our competitors and/or them deciding just to go ahead and idle operations that are un-economic.

As we think of where the prices are today, we believe that in the eastern United States that almost half of the production that is being produced today is not making money. The question is, how long will the owners of those properties continue to stay in business when they are not making cash flow? As they fall off, that may also present opportunities for us to pick up that demand.

We see demand being relatively flat. A lot's going to depend on what's going to go on with the lawsuits relative to the Clean Air Act, both the mercury rule that's having a hearing with the Supreme Court this year and the greenhouse gas rules. That's going to impact what ultimately the demand for utilities, or the demand for thermal coal will be in the United States.

We're too hopeful that the export market will rebound at some point in time in the not-too-distant future. That's another opportunity for increased demand. As we see demand being flat today, supply potentially coming off, we think that's going to provide opportunities for us to be the low-cost provider to go grab that market share as soon as it becomes available -- the timing of which is hard to predict, but we want to be in a position that when it materializes, we'll be a first mover to grab it.

Great. One last quick follow-up. You had mentioned the MATS rule and that 700,000-ton customer contract. Is there any other MATS exposure that's significant, or was that the major contract?

We don't believe under that contract they have the right to do what they are arguing. That's why we have a lawsuit. We do not believe any of our other contracts give any of our customers that opportunity. None of our contracts really give customers a right to terminate their agreement relative to this type of regulation.

Okay, thank you.

(Operator Instructions)

Your next question comes from the line of Mark Levin with BB&T Capital Markets. Please proceed.

Hi, guys, a couple quick questions. The first is on 2016 pricing. I think you referenced the fact you had about 30 million tons committed and priced at this point. I know you don't give specific price guidance, but maybe directionally how you're feeling about 2016 pricing vis-a-vis 2015, and maybe where you were this year?

I think as a follow-up to what I just said relative to supply, we're of the view that there will be a supply adjustment in 2015. We're expecting a supply fall-off, demand again to be stable.

We're also expecting with the crude oil reduction what that impact is going to be to natural gas. As we look to 2016, the gas prices will probably be higher than what the current curve is suggesting it to be. We believe the demand-supply balance will improve in 2016, and therefore it will give us opportunities to be able to sustain our revenue -- probably not totally at the level that we're expecting in 2015, but at a level that still allows us to maintain our current cash flow.

Related to that point, Joe, when you look at the market today, obviously exports have come off fairly considerably. There are tons coming on in the market as well from White Oak, for example, and clearly from others and into, as you mentioned, a flattish demand market.

Where are prices today? Have you seen any degradation in prices over the last month, couple of months, since the last time we spoke a quarter ago? How is the overall pricing environment in the Illinois Basin holding up, given those factors?

I would say for the low-chlorine coal, they have been holding pretty steady with where we were a quarter ago. It appears that the higher chlorine has probably dropped a couple bucks since the last quarter is what we're seeing in the marketplace today.

Would the pricing for low chlorine coal prices just across in the Illinois Basin be above $41, $42-ish, or is that too low or too high?

I would say that's -- yes, it could be a little low, but that's -- there's probably saying somewhere in the $41 to $43 range.

Got it. My next question has to do with gas. Obviously gas is now back at $2.85. The popular rule of thumb is when gas starts drifting below $3, the Illinois Basin can start feeling it a little bit. Have you seen the impact of lower gas prices? Put another way, if gas were to kind of stay around, let's just assume $2.85 for some period of time, how would that impact the Illinois Basin market and your ability to sell coal for 2016 and beyond?

I do believe that it has impacted -- so we have seen some reduction in demand currently, from lower natural gas prices. At the same time, it's not a significant amount.

We anticipated there would probably be more RFPs coming out for Illinois Basin than there actually has been. We have to assume the reason that they haven't come out is because they're relying a little bit more on natural gas than needing to add to their coal inventory. But as I mentioned earlier, we believe that with the contractual commitments that people have, that there's not a material amount that can be displaced, assuming the customers will honor their agreements.

One final question. We often think about Illinois Basin coal, and these tons that are sort of coming online as sort of back-filling the decline in central App. Can you maybe talk about the opportunity that the Illinois Basin has to compete in traditional northern Appalachian markets? Do you see that as a meaningful opportunity, or do you feel like it's more constrained to traditional central App stuff?

I would say it's more constrained. I think that northern App is fully supplied, and with the transportation differential that the northern App suppliers will be able to take care of their own market. It would be hard for Illinois Basin producers to try to go up and compete into that marketplace.

I think that would -- that's not to say -- in our situation we have flexibility under some of our contracts to supply either/or, so we may take an opportunity to do that. But as far as producers looking to try to take market share from northern App producers or the demand being greater there, I don't see that happening.

Great, perfect. I appreciate the color. Thanks, Joe.

Your next question comes from the line of Wilfredo Ortiz with Deutsche Bank. Please proceed.

Yes, good morning. Just a very quick question. On the prices that have been committed for 2015 through 2018, could you give us a sense as to what is more Illinois Basin versus central Appalachia, or is it fairly balanced, or more tilted to one versus the other?

For 2015, our exposure is mostly on the low sulfur side of our book. That would include our Gibson County product and our MC Mining product.

The out years, we would look at -- we've got contracts that are rolling off, and there's a blend across the board on that. Given the fact that we're heavily weighted towards Illinois Basin, you would see on a pro rata basis, it would open up on a -- similar to our production. But we think that those are more opportunities just to extend our current agreements where we've had long-term relationships with these customers and the price is re-opening, and it's time to have to re-price those contracts.

Got it. Thank you.

Thanks Wilfredo.

Your next question comes from the line of Lin Chen with Height.

Good morning. Thank you for taking my question. The first question is you just mentioned a couple times that you believe demand can be flat, but what we hear from the natural gas producer, their focus that every year there are some amount of coal-to-gas switch. It seems that the total demand for coal should be shrinking year on year. I'm wondering can you talk about a little bit more detail, why do you believe their demand can be flat for the next couple of years?

We believe -- the cap production's going to reduce, so when we're talking flat, we're talking for Illinois Basin and northern App.

For our markets.

For our markets. We believe that our markets, the cost of Illinois Basin and our northern App for the plants that they go to, can compete very well with natural gas.

I've got it. They talk about their market share in the Illinois Basin is going to be growing, even though total demand may be shrinking?

Yes, total demand may shrink. We don't really -- we think demand in the Illinois Basin's right at 140 million to 145 million tons, and we think it's going to stabilize there. That could move a little bit if the export market comes back, but we see the demand for Illinois Basin right at 140 million to 145 million tons per year, and that holding flat for the foreseeable future.

Great. Also, another question is that now you still have two publicly traded entities. One is ARLP, another is the GP -- AHGP.

Now the GP is trading at a similar yield to the LP, and it seems that the market does not give much fair appreciation for the GP higher distribution gross. I was wondering, do you think the strategy of about the merging of these two entities into one is something you can consider in the near future?

Right. We have considered that off and on, and we'll continue to look at that. It has been sort of up and down. Most of the year 2014 it was very comparable, like 10-basis-point difference pretty much on average. Then we had a little separation in the last quarter, and now it's coming back. It is something we'll continue to look at.

I think we expect -- we would like to believe that the AHGP should receive some premium for its growth, because we do believe we'll continue to be able to provide that distribution growth at ARLP. There should be some separation there. If not, we'll just have to (inaudible) right now we can do what's right for all shareholders.

Okay, thank you.

Ladies and gentlemen, with that concludes our Q&A session. I would now like to turn the conference back over to Mr. Brian Cantrell for closing remarks.

Thank you, Jackie, and appreciation to everyone for joining us today. Your support is well appreciated, and your interest in both ARLP and AHGP. We look forward to talking to you all on our next call in April. Thanks very much.

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