arb how would one reconcile the 12 months difference n start up times between ns line and km/mwe lines
looks like mobley/sherwodd being down was a big matter along with sxl delay.
I am curious if to the full extent was contractual commitment driven "... As a result, liquids production throughout the region has surpassed the capacity of the Partnership’s 60,000 Bbl/d Houston fractionator in Washington County, Pennsylvania and its 24,000 Bbl/d Siloam fractionator in South Shore, Kentucky....in the interim the Partnership has made arrangements for continued fractionation services for its producer customer’s excess volumes through third-party facilities. As part of these arrangements, the Partnership has incurred, and until the end of the year, will continue to incur additional transportation costs and realize lower fractionation income."
thank goodness for the higher institutional ownership or mwe would rally get beat up tomorrow more tnan what I think will happen with the .92 coverage , etc
arb good detective work. that could be the answer down to Corpus Cristi/ Formosa where kmp already has contracts through cpno acquisition
-they have similar level of cash available compared to other periods
-change in deferred revenues provided the ocf coverage of distributions thru third quarter 2013. this was first time they have not covered distributions with operating cash flow before changes in deferred revenue (.9x) compared to year ends 2003 thru 2013 final results. (covered distributions after net changes in deferred revenue included but only at 1x)
-minimum royalties are expiring at the lowest rate since 2007-2008
-deferred revenue increases are changing at a rate about 2.1 times faster than minimum royalties are expiring. 10 year average is around 1.9 so 2.1 is not bad
-raw spreadsheet numbers derived from "early" coal royalty outlook, based on an extrapolated view of Alpha 2014 guidance, suggests overall NRP coal royalties could be down 2% in best case to down 3% in worst case in 2014. Because extrapolation is based on only Alpha numbers adding a risk factor for unknowns at this early time could put coal royalties down 3% in best case to down 8% in worst case, but this again is a highly risked look. Also, aggregates could be flat to down (removing one time oci payment) and oil and gas should be up; so in aggregate if alpha raw data holds for 2014 at 2% to 3% down and with some help from expiring minimum royalties and the other business lines being flat to up, nrp could be able to hold their distributions at same level without any third party help in 2014 (ie their sponsor could step in to help which is a wildcard that is early overlooked)
cw again the article I read over the weekend says Iran still getting 80% of it revenue it needs form oil trades, so skyrocket may be over optimistic. again Libya is the wild card in my view
lets see, 150,000 fractional initially (initial pipe flow) so not too big, KMP and MWE, going to fave a 3 party fractionation JV; so what does the third party bring the most value for-as MWE is already a top notch fractionator. my guess is transporting fractionated products to the next step so does that narrow the scope. now epd already has atex and are seeking to expand it from NE so that could eliminate them.
ETP, oneok and dpm only do fractionation at this point so not sure they bring added value beyond fractionation.
So does that leave only NGLS and maybe PSX or Chevron or Exxon or Dow or Shell who can move fractionated ngl propane out of Mt Belvieu and or ethane to a cracker , etc
"...building approximately 200 miles of new pipeline of similar diameter from Natchitoches to a proposed Kinder Morgan/MarkWest Utica EMG joint venture fractionation facility with a third party that has existing facilities at Mont Belvieu. ...
...inservice second quarter 2016..3
Irene O. Haas - Wunderlich Securities Inc., Research Division
Okay. May I ask one more question? And on the operational end, you guys have done everything you possibly can really to connect up West Virginia. But it just seems like one hinge point really has to do with MarkWest plan. You only have one plan. So my question for you is, as you kind of project forward to 2014, have you worked in enough of a cushion just in case that the plant will go offline and things of that nature...
Gary C. Evans - Chairman and Chief Executive Officer
Well, it's a point that is very well taken. Remember, we're the ones that sold them the plant. It was our plant to begin with. So had our capital structure been different, we would have kept it. So the issues with MarkWest really began with the delay in getting the permits because of the location they chose. So they, obviously, had plans to put in 600 million cubic feet of gas of cryogenic processing. We had just a 200 million-a-day plant. So that is what created delays, which were really 7 months of last year. And then, of course, the issue this year was the landslide that knocked out the liquids line behind the plant. Obviously, none of us can control those things. I feel, today, things are a lot smoother. Any new plant has its start-ups and issues, and I feel like those are hopefully resolved. Now -- but are we a one-trick pony with MarkWest today? Absolutely. So we are doing everything we can to not be the case. And as I mentioned, these dry gas wells in Utica is no reason to be taking dry gas to a cryogenic processing plant. So we need to have direct interconnects with the pipelines to move that gas to Chicago and the Gulf Coast or wherever it's got to go. So we are working feverishly through Eureka Hunter to do that. As I mentioned, we're also buying firm transportation. It's very likely Eureka is going to have to put its own cryogenic processing plant or joint venture one with another midstream company in Ohio sometime in 2014..
What mhr lost in quarter which is minimum mwe lost also
"before the end of the third quarter that we had been shut-in the MarkWest, which is our only outlet for our Marcellus, as well as our Eureka Hunter Pipeline at this point, in West Virginia around the mid of the quarter. So around mid-August, we'd lost about 45 days of significant production to the tune of about 4,000 barrels a day;..."
jrad and others important caveat I should have posted. If I take out my risk adjustment for unknowns ie because this was so early my raw spreadsheet numbers derived down 2% in best case to down 3% in worst case, but again it is so early I was reluctant to project raw spreadsheet numbers in case something unexpected came in from other lessees in CAAP or prices or volumes faltered in IB or PRB or NAAP
Very sensitive. On an ongoing bases 65% to 70% of revenue currently come from coal royalties which are volume/price driven so even if price for discussion purposes makes up 50% of revenue stream directly, indirectly price will influence volumes in either direction
thumbs up twice, thanks for update on 2016. put on mlp iv board
saw typing error for met volumes should have said "Met volumes up 4.8% to down 20.0%"
Also because this is an "early" look, in final weightings the worst case raw weighted number was nearly a 10% down side, but I said there would be more shut in volumes and minimum payments before we got to worst case so I only gave worst case an 80% probability of concurring and I gave best case case a 100% probability of occurring
fyi in the normal course of business financing's mwe has started using ATM's for refinancing instead of SO's so more difficult to time
No 5 adjustment should have read
5- For 2013 third quarter Alpas % of total volumes was down from 21% to 16% of total royalty volumes, so weighted down range of Alpha impact to NRP in 2014 extrapolation "so total weighting for CAAP has now decreased to 38% from 48% of 2014 volumes and IB has increased to 27% from 20.8% of total volumes"
cw what do you thing the probably of a "workable" agreement is with Iran
Reading the iv bry board and others I get the impression Iran is still producing at a reasonable rate but exchanging volumes for goods so increase may not be as material as some are thinking. I wonder if Libya resolved its issues if that the impact would be greater than Iran
jrad thanks for comments. Couple of key points to my analysis and used extrapolated 2014 royalty range
1- The range of Alpha changes from 2013 to 2014 that was applied to NRP for 2014 ; before weighing changes for 3rd quarter 2013 results compared to 2012
Alpha raw changes in 2014 guidance compared to 2013 outlook
----Eastern Thermal volumes down 6.7% to 14.3%, current contracts show a 2.8% decline
----Met volumes down 4.8% to 10.0%
----PRB volumes flat to up around 2.7% , as a proxy for nrp
----Eastern Thermal prices down 4.3% to 9.9%
----Met prices down 13.1%
----PRB prices down 5% to flat, as a proxy for nrp
3rd quarter 2013 results compared to 2012 results above in extrapolation
2- IB reserves are around .05% for Alpha so I considered production would be at a similar weighting which means it was immaterial in Alphas eastern production production
3-For 3rd quarter 2013 IB revenue per ton was down approx 3% from 2012, so held it as constant for 2014 extrapolation
4-For 2013 3rd quarter NRP CAAP volumes are down around 10% from 2012 and IB volumes are up 6.2% and NAAP and PRB up around 1% each, so weighted down range of Alpha impact to NRP in 2014 extrapolation
5-For 2013 third quarter Alpas % of total volumes was down from 21% to 16% of total royalty volumes, so weighted down range of Alpha impact to NRP in 2014 extrapolation
6-Assumed NAAP, SAAP and GC volumes would be up 1% in 2014 vs 2013 and prices for NAAP, SAAP and GC would be flat for 2014 compared to 2013 in extrapolations
7 Assumed changes in volumes and prices in 1 thru 6 above would be equally weighted (50/50) to royally revenue
So taking raw changes in Alpha guidance from no. 1 above, adjusting for changes in 2 thru 6 and assumption from no. 7, etc. extrapolated to an early risk downside of 3% to 8% (rounded numbers)
Hope this helps and yes the continued increase deferred revenue is a red flag as they are getting closer to where distributions not being covered by cash from operations