Steve Zachritz

Growth, long-term horizon, commodities, oil & gas
Steve Zachritz
Growth, long-term horizon, commodities, oil & gas
Contributor since: 2007
Company: Zman's Energy Brain, LLC
Actually it was a very good quarter and more importantly a de-levering deal for them. All our comments can be found on it here:
http://bit.ly/1SwtGyP
That's just a revolver paydown seconary, a not a deal big enough to prompt any kind of change in thinking regarding a need for Street financing to grow at this time.
Hey, thanks for that.
ROSE budget effectively says "we don't need investment bankers"
Sellside loses interest en masse in a free cash flow, low cost, high return, break even at $30 to $40 per barrel name that could grow a lot faster but decided they didn't want to at present day pricing even as in the process they cut their base declines in half 2 years out while preserving the present value of their inventory and their balance sheet and creating the ability to rapidly ramp as prices and costs warrant.
ROSE 4Q14 Q&A
Q) Wolfcamp A returns
A) See slide 8
Type curve is 550 MBOE for a 5,000' well, this represents what we have out in the public domain
In the Permian, they asked themselves where can they get the best completions to fulfill drilling obligations (they had to drill the 8 wells they are drilling there this year) so they went to the highest return portions they could go after.
Q) Upper EFS update and how Netherland Sewell treated the Upper
A) Same as before (Northern Gates Ranch, Briscoe Ranch) – same as before, looks good where it is thick.
Have now drilled a 5,000 and a 10,000' lateral at Briscoe, saying they will see if they can get it completed.
Noted the upper is held by the drilling to the lower so no rush.
Q) asset sales
A) might sell Encinal area – EFS, not looking at selling Gaines
Q) Would the budget look more like the $700 to $800 mm if we are back in the $70 plus
A) We are thinking we want to live within cash flow in the long term now. See us closure to cash flow. As an industry, we can't keep spending 2x cash flow. It didn't seem to get us much, growing at the rates we were, over the last few years (in the market).
Q) Permian cost and lateral lengths.
A) Permian down 20 to 30%, same 5,000'. In the EFS, the laterals are going to be higher, at 7,000 as an average with some 10K wells
Q) Upper EFS – where
A) Gates SE – 11 and 3 well Gates E, and 3 wells in Dimmit. Briscoe Ranch could see the uppers done late this year as part of the discretionary $40 mm of the budget but that area is HBP.
Q) Permian drilling for 2015, at the end of the list, how much acreage will you have delineated in Reeves
A) Watch the Blue Duck well to the west. And the Rodeo State well to the north, looking at the map, looks like a majority delineated for the WC A this year.
Q) Production trajectory of guidance over next 2 years
A) Decline from 4Q14 to 4Q15 – we had as a company 500 wells at Jan 1. About 1/3 of those were drilled in 2014. Some 12 months ago, some just very recent. So base production declines at about 40%. Looking ahead 2 years, those 500 wells will be declining at about 19%. In other words, this takes the base decline by half in this period, so a lot more predictable going forward (so that is all in the guidance).
Q) Re not having to spend all of that $350 mm in 2016 (he's asking for maintenance)
A) In 2016, cash flow will be less than 2015 on current price. If they put capital into Gates Ranch they will be able to hold 2016 flat with 2015 for quite a bit less than the $350 mm. Higher prices, program expands, deferrals come off and they grow.
Call over – tone very neutral from analysts.
ROSE 4Q14 Q&A
Q) at what price ramp?
A) we watching service costs. Not giving a price at this point, but certainly not there today. Won't take us long to ramp back up. Had 80 wells at YE14 (60 EFS/ 20 Permian) that were drilled but not completed. So we could ramp that back up quickly with the right signals.
Q) 2016 guidance
A) Wanted to maintain a production level from which we can grow pretty well. We said $350 mm or less. As the wells age, the decline rate comes off and it becomes easier to defend the decline.
Reiterating that they will spend "up to" $350 mm. To hit the 60 MBOEpd in 2016, they will have to spend a good bit less than $350 mm. This is part of why you listen to calls before you change a rating when the basic logic of the moves isn't completely understood pre call.
There is a component in the budget for lease extensions. We have been successful in getting lease extensions.
Zcomment: I have heard it's gotten a lot cheaper to do so of late with lease owners in several plays actually not wanting to get drilled at these prices and therefore offering cheap extensions.
Q) Budget breakdown
A) 20% non drilling capex
$280 mm for drilling and completion – drill and complete 18 wells, most are longer lateral wells in the EFS ($50 mm to drill those (net)). The rest is on completing 10 wells that are already drilled. Those are longer laterals with bigger fracs (so that's $150 mm),
that leaves about $80 mm (half that is Permian non operated and the other $40 mm is on discretionary dollars).
Q) Timing of the year
A) If you divide the budget into quarters, 1Q and 4Q will be high and 2Q and 3Q will be low on spend
Q) Covenant renegotiation
A) the debt to ebitda one was the one that is going to give people trouble either this year or not. This is not a waiver, they amended it. It was not difficult, the banks were very supportive. It's not part of the drive to spend less, we have room to spend more, we just don't want to.
ROSE 4Q14 Notes
Delaware Basin delineation comments
3 new completions were slickwater (changed that in 2Q14 from gel)
Intrepid – south central portion, longest lateral to date. 7 day rate was 1,900 BOepd, 30 day rate over 1700 BOEpd, called the per foot rate of 246 very competitive.
the other two test expanded foot print of WC A areas
19 wells completed so far.
15 wells drilled and awaiting completion.
129 BOEpd per 1,000 foot with gel (4 wells) vs 290 boepd per 1,000' with slickwater
New wells outperforming type curve, look for a possible type curve upgrade later this year
Reserves:
Lack of reserve growth is function of 5 year rule. They put what would have been PUDs into location count. So when they do ramp back up, as long as they still like those wells (that is, they are economic) they will quickly hit the reserve statement.
ROSE operates in 2 of the best plays in NAM with low breakeven prices
EFS recovers almost 50% of reserves in first 2 years so they will spend at CF to hold volumes at 60 MBOepd and await better prices. Covenants allow them to be patient.
We've been here and seen this before. Have the ability to increase activity quickly in a better price environment.
Going to Q&A at the 33 minute mark …
Our call notes:
ROSE 4Q14 Notes
We simply do not think it is prudent to accelerate now with these prices. 1/3 of reserves of our wells and 50% of PV is produced and generated in the first 2 years of well life. (dear sellside, you're reaction to this is childlike in its simplicity … the reserves are still in the ground, they are opting to be prudent and leave them there, they're not gone, they will be produced at higher prices for lower costs but I digress)
And I expect the analysts who downgraded the name pre call to completely not care but to like it higher, later down the road.
Our EFS is economic to $30 per barrel
Our Wolfcamp is economic to low prices as well
Noting the financial headroom created by the new covenants (I've been talking waivers, this is a form of waiver)
Strong liquidity position
Senior note maturities are out in 2021 to 2024
Realized oil price was off $24 per barrel sequentially, lower to LLS due to weakness in differentials and an issue with their gatherer.
We expect oil at LLS – $12 per barrel before hedge. That's back to normal.
Production guidance for the 1Q, down 10%, down 9 to 10% YoY of 2014, all on decision to defer projects
Hedges
Oil – more than 100% hedged (may see some unwind some of that)
75% of NG covered
33% of NGL
In 2016, on a combined basis they are 1/3 hedged, will evaluate more hedges for 2016
2 Year Plan
– spend up to $350 mm in each year
– confirms no Gaines county(Midland) spending
– Bone Spring projects IRRs dropped too much to focus on that.
– would rather keep those in inventory instead of prod the BOE's here at low return (and low NPV)
28 operated completions in 2015 (will drill only 18 wells and will reduce the backlog by 10 to get to the 28 gross)
Will have up to 2 rigs in both areas
Sees defending the 60 mboepd level, live within cash flow.
Service Cost outlook
– falling at a fast pace
– in active talks now with vendors
– 600 rigs off so far, 700 more expected to go down over the next 6 months
– while costs are off, the rate of return is lower than it was prior to the down so want to preserve locations
Tom - Apologies for the delay, I don't actively monitor comments here. The covenants in the revolver are pretty lenient at 4.5x consolidated debt to EBITDA but they will be beyond that on a TTM basis at YE15 at current oil prices.
SJFarris - I don't see $20 as realistic for any length of time or even as a trough but no, they would not be EBITDA positive at that price given their cash cost structure. Very few names in the US would be. Our oil price prognostications are made on roughly a semi annual basis, the last for 2015 was made on December 24th at $77.50 as an average for the year, starting low and ending higher, much as we saw in 2009. We actually do quite a bit of work on the subject of oil and natural gas prices and have been pretty close over the last few years bu we are long term guys and see periods such as this as opportunities, once prices stabilize.
Monterey is there, to be sure but not the major focus of the name, as per their road show and quarterly comments.
Ocean - we don't own it. As noted in the article, when oil prices stabilize investors will seek out the unhedged, that have been beat down for that reason along with leverage, and high oil mix. We own 35 names. This is one that we are starting to watch. Book value has little to do with valuing E&P stocks. The balance sheet is covered by our cheat sheet but can be found right at the top of the Q: http://1.usa.gov/1D8tWfK
$85 equates to current 2015 Street, get's very close on them to current Street EBITDA so we call that base. We can run a $60 on the current model for 2015 but would ratchet back spending / growth a touch at that level as the operators will go slower there. Not doing a 2016 view at this time as that's not in most peoples time frame for forward valuation. Also, we've been pretty good at getting prices close in the past and don't see $60 as likely next year. A lot of people take the current trend in prices and assume something has changed. We said $100+ was too high all year long and ended 2013 with a 4Q14 estimate of $80 +/- $10 and feel pretty good about that as an average. This is a short term supply issue, very unlike 2008 and overdone to the downside at this point. Our 2015 average WTI price was $92.50 (over the summer of 2014 and still is but will be revised into the mid $80s soon).
Baseballer - yes, they will be in compliance then too.
Dan - we added to our TPLM holdings at the close of their call yesterday. Likely they used the remaining 1.1 mm share authorization today.
O2345 - time frame to a sale of what?
A few food for that points on that analogy and on the new plan.
Thought on TMS is that it was called a core at inception but never one in terms of capex. D&C of 50% Bakken, 40% EFS, 10% TMS.
TMS wells have largely been successful while the Utica was in a non core portion of the liquids window of that play.
TMS being scaled back due high well costs vs lower current oil prices and no relief (yet) on service costs.
It makes more sense to drill quick payback, quick production add wells in the FBIR and SE Williams for less CWC per copy vs current $12 to $13 mm price tag on the TMS. In the meantime, they have 3+2 leases with cheap optionality.
At the current strip, and with a carbon copy of 2014 capex, 2015 debt to EBITDA metric would have ballooned. Move makes sense to us and minimal drop in guidance vs current Street speaks to improving wells in the 2 real core plays.
More color over at http://bit.ly/pqYr1I
Thanks.
The weekly wrap:
http://bit.ly/1n9axSZ
I did on the site yesterday. May do one for SA. Still wrapping up the Permian quarters for our piece there.
SA released our 2Q14 pre call piece from embargo this morning:
http://seekingalpha.co...
BCEI Q&A 4
comments on extended reach
- we really think we've made a lot of progress
- the IRR is obviously higher than on the short wells
Q) Geology and the 60 day rates not declining much at all, comparing the 9,000' Nio C vs 9,000 ' Nio B bench lateral
A) confident they are in line, with each other, 40 stages, saying its like having 40 indiv. verticals unload at the same time, thinking the unload different so you get a higher IP if they all unload at differnt times, the ones that unload a bit slower have the flatter but in essence they are all in the ragne.
Saying the IRR s are 15 to 20% over the shorter laterals (and then said that's conservative)
Q) All 28 stage going forward?
A) not yet but sounds likely. Those cost $250 K extra, going to be offset by the economics it would appear
Q) Long lateral risk
A) risk would have been failure at the end of last year, so you don't want a costly long lateral ... now moving in the direction of doing these with no or minimla issues. Will drill about 11 this year.
Expect 2015 to have a much greater proportion of long rach laterals.
Acreage position of course drives that a bit so you will always have some of the shorter, 4,000' laterals
Q) any 56 to 60 stage longer laterals?
A) not in the plan for the rest of the 2014 wells yet but they are looking hard at it.
Q) 7,500 laterals
A) a little less risk that the longer ones, easier to run liner, less stages to be concerned with . But this year, no problems in running the 3 long ones, so pref would be to do 9,000's . In tighter spacing however it may be better to do 7,500' as the toes of the wells can waiver a bit and you don't want your toes to get too close together (communicate).
Q) new acres
A) suspect drilling will focus on north side
Q) Macquarie question on using more sand in the 28 stage
A) Looking at it, looking at yet tighter stage spacing, plug n perf
Q) Sev tax ? asking about after year 1 for the hz; I get the question.
A) I think didn't quite answer that one. Just sticking to 10%.
Q) Open season for White Cliffs?
A) soon
Q) Ext reach lateral choke question?
A) We flow them back a little differently, on a 4,000 ' lateral we're doing 700 to 800 bofpd , going to be proportionally higher on the longer ones. We not changing this up. Satisfied with the curves. You can do the most damage by pulling too hard early, nothing new there, if you flow back soft (slow) then there is no damage to the reservoir.
BCEI Q&A 3
Q) New acres plans
A) Will start drilling on the new acreage in 4Q14 (faster than I thought), will do 4 to 5 wells in 4Q, will get ahead on a little that will be expiring soon.
- have 700 net locations
- those are based on 80 acre spacing in the Nio B, Nio C and 160 acre spacing in the Codell
- 23,000 of the new 35,000 net are probably going to look a lot like our legacy acreage
- plan to have 2 rigs on it by January
- with same 4 in the legacy
- not giving well count now as they are going to be doing more long reach laterals next year. I really like these guys …
BCEI Q&A 2
Q) 28 stage question
A) WE DO NOT SEE THE BETTER PRODUCTION AS ACCELERATION. It's better stimulation of the rock, more uniform along the later. HELLO HIGHER EUR.
We are very encouraged by fraccing up the rock around the wellbore, not having the fractures come out to say hi to the other wellbore, so bigger EUR
Q) Long lateral denser spacing?
A) We are going to be doing that. It will be 56 stages and we have the tech to do that now.
Q) And same in Codell
A) We have not done it yet. Looking at it now.
BCEI Q&A 1
Q) 5 well pad question
A) – 3 Nio B staggered on top of 2 Nio C wells – all with 28 stage, 4 mm pound fracs
– Begins drilling this monthresults October/November
Q) FERC rulling
A) Never have seen that happen before, looking for options to move our crude, we don't see it as a problem to move it, and see expansions of 3 lines as giving a lot of capacity coming into the Basin. So we are maintaining $11 to $14 off WTI inthe quarter.
Q) Codell thin zone test, how many acres derisked
A) Very encouraged by the rate on this well, this is 426 BOEpd, first one they did a year ago was 330 BOEpd … said it could add 3000 to 5000 net acres with one more test.
Also said they are evaluating Codell on the new acreage now, results of that analysis in 3 to 4 weeks.
Q) Eastern Codell well test and the Carlile shale – did you dip into that zone, is it more tempting.
A) we are targetting such a thin zone with the Carlile, the source for the Codell, is right under it. The Codell is an oil bearing shale, we don't know if we have contribution from the Carlile, working to figure that out now
My question would be if you land lower do you get better contribution from the combined. He thinks they are probably getting some sort of contribution from the Carlilel
next question would be as Codell thins further to the east could the Carlile be a standalone target. They don't have an answer on that yet but bet they will have one in a few months.
Q) Plug and Perf
A) Could be a bit more costly, takes long but you also get better placement, saying you don't want to over displace your fracs if you are using gel, saying it's probably just north of $4.5 mm CWC for those … still would be nice economics and that's not assuming an uplift from the better targeting.
Q) White Cliffs
A) We will go into the open season with others and not sure we will get those same amount of volumes as we had before FERC killed our prior deal. They do think the will get the same pricing , at about $9.20 off WTI though.
Q) Carlile – why industry has not drilled it so far?
A) Nio and Codell were seen as more attractive, Codell was thicker, with Carlile as source, most figured that at least for now they were good, didn't need to yet go to the Carlile. Basically its what's next. Saying they will probably be the leader on the Carlile, its' 30 to 35 ' thick at the base of the Codell. Nice. A fat new play.
He mentioned testing the A bench in the answer
BCEI 2Q14 Notes
Short prepared remarks today to leave lots of time for Q&A
We had a very solid quarter with produciton right on plan
We said look for a linear year, adding about 3,000 boepd per quarter … so far so good
New acquisiton – tranformative to support future growth
on a prelim basis
– added 700 net locations taking total to 2,000 net (not news)
– saying easy to add acreage
CEO selection process
- ongoing
- down to a short list now after considering many
He said on acquisitions, when you see their releases you'll say "that makes sense" ; saying when you see the CEO announced, you'll say the same
Relieved to see the ballot initiatives in CO pulled. Time to stop talking about politics and talk about how focused they are on their growht
See no impediments to making their forecasts
Saying the catalyst program doing very well
Very high level of confidence in the program.
Earnigs and Cash floow
- right on plan for production and # of wells completed and LOE
- LOE took a big step down due to better weather and higher volumes and it will fall rest of year
- same for cash G&A
Severance Taxes – as a result of doing business in CO we are no longer getting help from drilling verticals
- during the quarter, we got a higher tax rate from our accountants , this resulted in a higher than expected lag in credits as the wells are not eligible for credits in their first year of production.
- other bad news – White Cliffs pipelline – FERC ruling was without precident, stipulated a new open season on that line, negating an agreement they had in that place. So they will be going through the process to get firm with White Cliffs again.
High confidence that midstream will keep pace with growth in the Basin.
The HY deal put cash on the balance sheet in prep for the 2015 program which will be their biggest year yet.
Operations Update
We have learned a lot sense the super section call on Q1
- More confident than ever that 40 acre spacing is the standard in the Nio B AND the Nio C
- Definitely see 28 stage frac is the way to go
- 4 well pad – much greater 60 day rate than prior wells (only the middle 2 had the 28 stage)
- $500 K increase in revenue over first 2 months per well due to the 28 stage frac
- 5 well pad as per post coming up with Nio B and Nio C with 28 stages in all
- they are going to do PnP wells later this year … until now they've been only sliding sleeves guys
- they see a possible INCREASE IN RECOVERIES – hello EUR upgrade as mentioned as possible in the post
Codell
- 426 BOEpd in a 6' section – just awesome – 6,000' vertical and 4,000' laterally and stayed within the zone
- will do another thin sectoin 6' thick well in 4Q
Long Laterals – deets above in the post
- production profile is very interesting, lower IP 30's converge at 60 days, saying the lowest one only fell 1% from the 30 day rate to the 60 day rate (see #s in post)
- great majority of acreage is contiguous in nature and lends itself to long laterals – hey, that sounds familiar.
Q&A starting now …
Bill yeah, exactly. - will drop my notes in here in a bit.
$BCEI - early knee jerk in progress. Company hitting on all cylinders. Footprint just got more valuable.
the 28 stage downspaced fracs doing very well on the long term data. Usually EURs travel lower as you get tighter on spacing... new recipe may preclude that move.
Codell test in the thin zone is key to unlocking more acreage for that as well.
Good call underway. Flat 3Q vs 2Q gave some temporary pause but that's noise in a very good operations update.
3Q14 call to have two obvious catalysts in the form of the oily Green formation well flowing back now and then an upper Deep Pink well.
They're not going to be flashy IP press release types (which is smart)
4Q to see another ramp
Seeing no interference on the stacked laterals
3 more wells in 2H14 outside of the NS 3P area
Given the step out wells they could see significant expansion of the proved footprint.
Essentially in line quarter and guidance for the first quarter out of the IPO gate. Stronger well results than at IPO time. Western side oil test likely a 3Q event. CC in 20 minutes.
Blueice - we liked the deal, it was open all morning as per above.
Pablo - it was open to the public all morning long.
Today's post free to the public for KOG:
http://bit.ly/1kV6FU7
Thoughts: We like the deal but after 6 years of ownership are sorry to see them go. We don't see it as the take under the market initial will. Please see the Monday Post for further details and running comments during the conference call at http://bit.ly/pqYr1I.