I think I used the words "maybe they could ..." I don't know whether they could or not. Only NRP has the info necessary to determine the choices and values. And they aren't talking much. I was just pointing out that some analysts think the Ciner Wyoming property is worth a lot more than I thought.
FBR recommended CINR yesterday aith a price target of $ 35. I don't think that target is reasonable, but it would equate to a value of $ 720 MM for CINR (adding back the public company debt), not including any value for the IDRs. Since NRP's interest in CINR Wyoming isn't subject to any IDRs, this would probably equal a value of at least $ 700 MM for NRP's interest. I have been using a value of about $ 500 MM in valuing NRP.
CINR's price isn't there yet, and I'm not optimistic that it will, any time soon. But it's good sign for NRP.
My recollection is that when NRP extended its credit line last year, they put up everything they owned, except CINR Wyoming, as security. Maybe they could do a separate financing of just the CINR Wyoming interest to fix their debt maturity problem.
So we share an interest in ARLP and a frustration with SCHW.
I like the word "intermittent"; it sounds better than the "temporary" they were using earlier today.
I'm in the middle of closing my E*Trade account because they can't get the 1099 right. But now I'm wondering which is worse - bad tax reporting or a complete inability to access my account.
Slight corrections - Mr. Cline paid $ 7.5 MM for the reserves, not $ 10 MM. And the purchase took place in 2004, not 2002. For an old guy, my memory was pretty close.
Sure I do. My numbers may be slightly off but the answer bis this - NRP owns approximately 200 MM tons of coal reserves around the Hillsboro/Deer Run mine. FELP itself owns about 600 MM additional tons of reserves at the mine, and I think Chris Cline owns another billion tons. I don't think Mr Cline's reserves are adjacent or developed.
The story is actually interesting. Back in 2002, Mr Cline bought the mineral reserves from the Town of Hillsboro for pennies. I think he paid something like $ 10 million for 2 billion tons of undeveloped reserves, plus he agreed to build a mine and bring jobs to the town. He spent $ 300 MM or more building the mine. Most of the cost of the mine was funded by NRP, which bought 200 MM tons of reserves from Mr. Cline for $ 255 MM, which was used to build the mine.
BTW, the following is the best (and probably the most useless) investing advice you will get today - Mr. Cline is by far the best investor in coal over the last 20 years. If you read that he is buying something, you should follow him. If you read that he is selling something, you should stay as far away from whatever he's selling as you can. Just ask NRP (the 2 Gatling mines), Mr. Murray (control of FELP), and maybe SXCP (the Louisiana coal handling terminal).
I don't know the layout of the mine so I don't know if mining could be switched from one portion of the reserves to another. But if the mine is in operation, NRP at the very least gets $ 30 MM per year in minimum royalties. Until it re-opens, though, NRP is getting just about nothing.
Yesterday, some banks upgraded SXC to strong buy - the parent, not the MLP. So you certainly may be right about the tariffs having an effect.
And if the reference to "shorts" was for me, I'm not short. I'm simply out. I've been tempted to buy some NRP when it drops to the $ 7 range, and the last 2 times the trade would have worked. But last year, the 2 times I bought into a drop, NRP simply dropped more. So I'm waiting for the Q1 release and hopefully some guidance. In the absence of any guidance, I think NRP is simply a gamble with my having no edge.
SunCoke Energy, Inc. (SXC) has divested its coal mining business to Revelation Energy, LLC in a transaction that includes substantially all of SXC’s remaining coal mining assets, mineral leases, real estate and mining reclamation costs. Under the terms of the deal, which closed April 6, Revelation Energy will receive approximately $10.3 million from SXC to take ownership of the assets and associated costs.
The deal excludes SunCoke’s legacy black lung and workers’ compensation liabilities, and certain properties that are necessary for Jewell Coke’s operation or were unavailable for transfer based on contractual provisions. SunCoke may transfer other properties to Revelation Energy after closing, subject to required consents, for additional payment to Revelation of up to $0.7 million.
Revelation also agreed to deliver 300,000 tons of met coal annually to SXC for 5 years at "favorable" prices; they don't say what that means.
So SXC pays Revelation to take the mines off its hands, and SXC keeps the employee liabilities. I guess that tells us what met coal mines are worth these days.
And this is not a shot at NRP, which still doesn't trade on fundamentals. It's just coal-related news that I thought was interesting.
Actually, EPD is 40% oil services. Per the 10-K, crude oil pipelines and services generated $ 10.3 billion in revenue in 2015, out of a total of $ 27.0 billion of revenue. In 2014, the oil-related revenue was a higher percentage of the total.
And what I'm about to add has absolutely nothing directly related to EPD, but it's interesting, and it shows that counterparty risk isn't the only thing to worry about with natural gas.
Tallgrass Development (related to TEP/TEGP) just agreed to buy an additional interest in the Rockies Express Pipeline (REX); Credit Suisse wrote up a large article about the deal and they pointed out that a lot of REX's legacy contracts were signed when natural gas prices were much higher and the price they get for transportation is $ 1.50 per mcf. Current recontractings are closer to 30-50 cents per mcf. REX is a very long pipeline and I have no idea how far they were transporting the natural gas. The point I took from the article was just reinforcement of the idea that lower oil & natural gas prices are working their way through the system and everyone in the food chain suffers. REX's hope is that it can increase the volume it carries by enough to offset the drop in price.
Again, just a general comment, not specific to EPD, but it affects everyone.
Anyway, EPD's ability to refinance at incredible good rates and for incredibly long periods of time is a really good sign.
What difference would they make?
I checked google finance (btw, that site makes Yahoo Finance look fantastic) and the last projection I saw was $ 1.30 for Q1 and $ 5.32 for all of 2016. That analyst also had a $ 7 price target. So they are projecting a 1.3 PE ratio? In that case, what difference do the Q1 numbers make?
We will know more as CINR, FELP and WLL report. But my guess numbers for Q1 are revenues of $ 101 MM, operating income of $ 35 MM, and DCF of $ 25 MM. (The comparable numbers for Q1 2015 were revenues - $ 110 MM; operating income - $ 40 MM; and DCF - $ 53 MM) My 2016 numbers exclude unusual items like the sales of assets that NRP announced. I don't know if they were able to close those 2 sales in Q1, but NRP includes all of the proceeds in DCF. So those sales would hugely increase DCF, and depending on whether they have a profit or loss on the sales, that profit/loss would affect revenue and operating income.
In Q1 2015, DCF had a huge benefit from working capital adjustments which is unusual for a Q1. Usually, the Q1 working capital adjustment is a negative due to the timing of the payment of real estate taxes and bonuses. In Q1 2015, NRP’s accounts receivable dropped $ 14 MM due to a drop off in business. But the receipt of those accounts receivable helped DCF. To some extent that might recur, but it won’t be as big a deal this year.
1 more post to go.
So the good news (for new investors) - ARLP is priced for a complete disaster. I think/hope that everything I have just said is already priced in.
For the past few months, AHGP has been trading at a higher yield than ARLP. This only makes sense if a distribution cut is imminent because AHGP would suffer disproportionately from a cut (IDRs). The yield differential peaked in the first half of March and has now been reduced. I take this to mean that people are a little more comfortable with the distribution being maintained or cut just a little.
If I was aggressive, I would buy ARLP and short AHGP. But I don't short things, so probably I will buy some ARLP with a very short leash.
And if you like ARLP, you really should be buying AHGP. It's the same operation with a higher yield.
I am tempted to buy back into ARLP for another short-term trade, but consider:
1. At 12/31/14 ARLP had contracted for the sale of 39.3 MM tons in 2015, not including White Oak/Hamilton. In Q4, ARLP acquired the rest of Hamilton and picked up some sales as a result. Total tons sold in 2015 was 41.1 MM, which means that basically ARLP didn't sell any incremental net tons in 2015. Basically, the deferrals of existing 2015 orders offset any new sales contracts they entered into for 2015.
2. At 12/31/14 ARLP had contracted for 28.9 MM tons in 2016. At 12/31/15, including the contracts picked up from Hamilton, 2016 contracted tons was 34.3 MM, meaning that they added a few MM tons in net new sales.
3. ARLP attributed the slow sales to (1) lower demand from utilities (weather, slow electric growth), (2) high inventories at the utilities, which ARLP hoped would be solved by a cold winter, and (3) a general reluctance by the utilities to enter into longer-term contracts and instead rely on the spot market.
4. So now look to 2017 - at 12/31/15, ARLP had contracted for the sale of 19.1 MM tons in 2017. I would bet that ARLP hasn't sold any significant amount of 2017 coal in Q1 - the winter was way warmer than ARLP had hoped for. Pricing seems to still be terrible. Even if ARLP is somehow able to reach 30 MM tons of sales in 2017, the poor pricing will kill DCF. If the projected 36 MM tons of sales in 2016 only produce 1.1 - 1.2X coverage, a further 20% drop in 2017 tons sold plus reduced prices doesn't support a positive coverage ratio.
5. ARLP has the best management in coal. Unless they see things in a sunnier light, I think they will cut the distribution sooner rather than later.
1 more post to finish.
Among Endo’s branded products, management is particularly excited about Xiaflex, currently used to treat Dupuytren’s contracture and Peyronie’s disease, conditions related to collagen disorders, but it could have more than a dozen additional uses.
Xiaflex, which posted 2015 sales of $158 million, could soon become Endo’s best seller. Its current No. 1 product, Voltaren Gel, a nonsteroidal anti-inflammatory for the relief of joint pain, had $207 million in sales last year. But it faces competition from a generic version launched last month. Endo’s management also is excited about Belbuca, a treatment for chronic pain that has just been launched.
Good for BSTC, if the prediction is good.
3 questions - what do you estimate the distribution coverage ratio to be in 2017? This is a general question based on what we know about ARLP's contracted sales for 2017 including contracts that are likely to be signed this year.
Does your answer change if Hillary/Bernie are elected?
Does your answer change if Donald/Ted/whoever gets elected?
I'm not trying to start a political discussion; I'm just interested in the answer as it relates to coal.
You're right but it's a little more confusing than that.
NRP is not the borrower on this loan. The borrower is just NRP Oil & Gas, LLC, a subsidiary LLC that NRP formed to make oil & gas investments. The agreement eliminates the requirement that NRP Oil & Gas LLC deliver a clean opinion with its 2015 financial statements. From the release: "In addition, the Fourth Amendment waives the delivery of 2015 audited financials containing an audit opinion containing “a “going concern” or like qualification or exception” as an event of default under the facility."
So this does not apply to NRP's own loans (which are about 90% of the overall debt) and it doesn't apply to the oil & gas loan next year.
But you make a good point, which I missed. I only track the parent company's loans. But since the lender agreed to accept a going concern opinion on NRP Oil & Gas LLC's 2015 financials, it means that NRP was facing a default on the oil & gas loan without the subsidiary getting a clean opinion on its financials. That would explain why NRP was forced into accepting the new terms.
It's tax season and I can't check on the detail right now. But often, a company's debts will be written such that a default on 1 loan will trigger covenant violations on all the loans. If that's correct, then this was a huge deal to NRP, and getting the loan renegotiated was really important.
BTW, the new loan terms also require NRP Oil & Gas LLC to use all cash flow from the oil investments to pay down the oil & gas loan. Also, any sales of the oil properties must be used to pay down the debt. I have no way of knowing if NRP Oil & Gas LLC owns 100% of NRP's oil & gas investments, or only a portion. But don't count on the oil & gas DCF being used for anything else.
That may also be why NRP isn't buying back its 2018 bonds at a discount. It may be required by its lenders to pay off other debt first.
Here's the lender problem as I see it. The bankers have access to information that NRP has chosen not to make public. For instance, NRP has declined to estimate cash flow for 2016 because of the difficult situation in the various energy markets. That won't work for a lender, especially a prospective lender. They will want some assurances that they will be repaid. So I have to assume NRP has shared or will share non-public information with them. So far, that hasn't helped in refinancing loans, but it's too soon to say.
Take the oil & gas loan - it was due in 2019, with loan limits being recomputed every 6 months. The existing loan limit, determined last October, was $ 85 MM. They just agreed to cut the limit to $ 50 MM by October and they agreed to a higher interest rate. The only reason I can see for that agreement is that it's better (for NRP) than the existing agreement.
From the outside, this makes little sense - in Oct 2015, WTI averaged around $ 45/barrel and it's currently around $ 40. Whatever Bakken oil goes for, I assume the trend is similar. So from the outside, I would not have expected another 40% drop in the oil & gas loan limit. The bankers must have access to other information that sounds worse than what is publicly available (that sounds hard to believe).
So I think things are worse than investors realize.
As of the 10-K date, NRP had $ 81 MM of debt repayments due in 2016, which I thought was entirely workable. Today's announcement said that NRP will also repay $ 10 MM of the oil & gas reserve-based debt now, another $ 5 MM by August 1 and another $ 20 MM by October 1. In addition, the next scheduled computation of the loan limit is in November. And it's convoluted, but the interest rate on the oil & gas RBL now appears to be LIBOR plus 4%. I don't know which option NRP has chosen in the past, but I think they were paying LIBOR plus 1%. The amount of the RBL is not that big so the higher interest rate doesn't hurt all that much.
The RBL was scheduled to come due in 2019, so this acceleration moves it ahead (in time, not in legal priority) of the 2018 bonds.
So now the 2016 repayments are up to $ 116 MM. Still workable, but less room to maneuver.
Q1 DCF should be good, as long as the scheduled asset sales take place as planned. But now most of that $ 47 MM is spoken for.
Coal stockpiles at electric generating facilities totaled 197 million tons at the end of 2015, the highest level since June 2012 and the highest year-end inventories in at least 25 years. More than 40 million tons of coal were added to stockpiles at electric generating facilities from September through December, the largest build during that timespan in at least 15 years. In addition to relatively low overall electricity generation, largely attributable to the warmest winter on record, coal-fired electricity has recently been losing market share to electricity produced using natural gas and renewable resources.
Coal stockpiles typically follow a seasonal pattern in which stocks build during the lower electricity demand periods of the spring and fall and then get drawn down during periods of higher electricity demand in the summer and winter. In 2015, the stockpile build from August to December was 40 million tons, far higher than the 11 million ton average stockpile build for these months over 2001-14. Coal stockpiles typically decrease in December, averaging a roughly 3 million ton decline for the month over 2001-14. However, stockpiles this December increased by more than 8 million tons.
As stockpiles grew toward the end of 2015, shipments of coal by rail fell. Weekly coal railcar loadings averaged nearly 94,000 carloads per week from September through December 2015, 22% below average loadings for that time of year over the previous five years. Railcar loadings were even lower in the first months of 2016. Through February, weekly coal railcar loadings averaged slightly more than 75,000 carloads, 35% below the previous five-year average.
Relatively high coal stockpile levels at the end of 2015 come despite a reduction in coal-fired generation capacity. From 2010 to 2015, total U.S. coal generating capacity declined 10%, falling by nearly 33 gigawatts (GW) to 285 GW. One way of measuring coal stockpiles while accounting for the overall change in generating capacity is to calculate days of burn. This calculation considers the current stockpile level at each generator and its estimated consumption (burn) rates in coming months, based on the average consumption rates for those months over the past three years. This measure approximates how many days the generator could run at historical levels before depleting its existing stockpile.
Subbituminous coal-fired generators currently average 95 days of burn, up sharply from an annual low of 65 days in June and the highest level since 2010. Bituminous coal-fired generators currently average 91 days of burn, up from an annual low of 73 days of burn in June and the highest levels since February 2013. Subbituminous and bituminous generators make up most of the coal fleet, with 144 GW and 124 GW of capacity, respectively, at the end of 2015.
You're right. I should have stuck to my main point - the deal was never big enough to matter. It hasn't been a disaster; it hasn't been a home run. It was just something that hasn't produced great returns.
Another completely irrelevant story - there used to be another coal royalty MLP - PVR. It later acquired its GP and then it merged into RGP.
NRP was always bigger and better than PVR; bigger simply because it was bigger, and better because of NRP's focus on met coal, which was far more profitable. Both saw the need to diversify. I used to own PVR because it had a higher yield and I got in the habit of following NRP as well, just to compare them. NRP took small steps to diversify but kept its main focus on coal until 2013. PVR made just 1 deal - in 2012, it acquired a midstream operation in the Marcellus - Chief Gathering, I think the name was. PVR paid a huge price for Chief; I think the price was bigger than PVR's market cap. I went crazy - the Chief Gathering business was still in the start-up phase and no way did it throw off enough cash to justify the purchase price.
You know the rest of the story - midstream went crazy, the Marcellus went crazy and PVR got acquired by RGP. RGP tried to sell the coal royalty business but as I recall there were no takers. And NRP ended up as a coal royalty company with bits and pieces of other businesses tacked on.
So 2 points - first, I was wrong all along because I focused on today's cash flow instead of growth, and because I missed the signs about met coal. And second, both NRP and PVR recognized coal's problems but it was PVR's management that bet big and won. Lesson? If your business is in a secular decline, sell it or use the cash flow to buy a big growing business that will offset the decline.
Now if I could stop having to learn the first lesson over and over.