Brace #1H

STATE COLLEGE, Pa.,

Sept. 26, 2012

(GLOBE NEWSWIRE) --

Rex Energy Corporation

(Nasdaq:REXX) today announced initial production results from its first Ohio

Utica Shale well and provided an update on its operations.

The Brace #1H, located in Carroll County, Ohio,was brought online to sales

from its 60-day resting period at a 24-hour sales rate, assuming full ethane

recovery, of 1,094 Boe/d (43% NGLs, 31% gas, 26% condensate). The well went

on to average a 5-day sales rate, assuming full ethane recovery, of 1,008 Boe/d

(43% NGLs, 30% gas, 27% condensate). The well produced with an average casing

pressure of 1,502 psi during the initial 24-hour sales period and 1,533 psi

during the average 5-day sales period on a 24/64 inch choke. The well was

drilled to a total measured depth of 12,332 feet with a lateral length of

approximately 4,170 feet and was completed in 17 stages. Based on

composition analysis, the oil from the Brace #1H is 60.1 degree API gravity

and the gas is approximately 1,250 BTU.

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Replies to This Discussion

Permalink Reply by Robin Hood on September 27, 2012 at 10:13am

After that remark, It will pay for a new husband for the wife and barely a room for you in shanty town.

Permalink Reply by Ron D. Jockefeller on September 27, 2012 at 12:06am

BMO's take on the Brace #1H:

Rex Energy announced that its first Ohio (Carroll County) Utica well (Brace #1H) achieved a 24hr rate of 1,094Boe/d (911Boe/d excluding ethane) and a five-day rate of 1,008Boe/d (839Boe/d excluding ethane).

This compares to a ~1,000Boe/d "peak rate" reported by Chesapeake (including ethane) as the average for its first 28 wells.  

While the headline IP rate could disappoint some given recent Gulfport announcements to the south, we'd note the following. First, Rex's Brace #1H has a higher liquids mix compared to the average of the CHK wells. Rex reported the production mix to be 43% NGL, 26% oil, and 31% gas compared to 15% NGL, 21% oil, and 64% gas for CHK. Second, Rex reported a more credible 24hr and five-day sales rate, compared to "peak rates" that other operators have reported.

Also, the Brace #1H was drilled with a 4,170' lateral, compared to Gulfport's Boy Scout 1-33H well with a 7,974' lateral. Third, in our model, the higher liquids mix has a net positive impact than any potential EUR adjustments based on the IP rate.

Impact: After considering the higher liquids mix, longer time period IP rate, and shorter lateral length, we consider this a positive test and comparisons with Gulfport's IP rates aren't as relevant. Also, Rex announced preliminary 2013 plans to drill nine wells (complete six) in Carroll County (15,400 net acres).

Permalink Reply by Bluflame on September 27, 2012 at 1:37am

Ron,

   This pronouncement muddies the water on a confusing aspect of well results. i.e., Globe Newswire reports 26% "condensate" while BMO reports 26% "oil".  So what exactly are "condensates"? On other posts, they've been defined as "natural gasoline", which is purported to be valued at ~$60/barrel vs ~$90/barrel for oil. Can you shed some light on this confusing matter?  BTW, what or who is BMO?

   I still think this Brace #1H well is pretty consistent with other Carroll County wells, CHK cites the "average" of their first 28 wells and the Rex numbers could easily fit within that average.

Thanks,

BluFlame

Permalink Reply by Ron D. Jockefeller on September 27, 2012 at 2:52am

BMO is here:  http://www.bmo.com/home

The oil & gas industry uses exceptionally confusing terms, and you'll find different definitions for the same thing depending upon context.  For example, LNG, LPG, NGLs, CNG are all related, but different.  It doesn't help that the profession of journalism is populated entirely by idiots, which leads to non-industry press accounts being wrong at least half of the time.

"Condensates" refers to the that part of the gaseous stream which upon hitting the surface at the wellhead, where temperatures and pressures are lower than underground, condenses on it's own into a liquid.  Because this liquid was a fuel for early automobiles, some people call it "natural gasoline".  Today's engines can not run on "natural gasoline" - but this liquid is still valuable because it is energy dense, is easy to transport, and can be blended into today's refined products.

Many press accounts refer to all liquids as "oil" because often the state filings required only that producers report "oil" or "gas".  So for regulatory reasons sometimes oil means oil, sometimes it means oil+condensates, and sometimes it means all liquids.

The Rex well results are good.  The Utica/PP is still on track to be the next Eagle Ford, but it is still early days.  There should be a bunch of wells reporting in the next 8 weeks, but the big news will be the EnerVest sale/asset swap which will be the new mark for acreage.  That will be announced in the next 75 days, maybe the next 30 days.  Hang tight.

Permalink Reply by Bluflame on September 27, 2012 at 3:55am

Ron,

  Since BMO is an investment organization, I think we can attach more credibility to the Rex Energy press release noting "condensates" versus the BMO assertion of "oil". This is consistent with your opinion of "non-industry press accounts". Comparing early Utica results to Eagle Ford wells, I agree that we seem to be on track for becoming the next Eagle Ford.  Let's hope lease prices follow suit with the Eagle Ford!

   Relative to the Enervest deal, recall that CHK's JV deal with Total was for $13K/acre. I think it will prove difficult to top that. Hope I'm wrong!

BluFlame

Permalink Reply by Ron D. Jockefeller on September 27, 2012 at 6:54am

Generally, most reputable investment organizations will be less likely to overstate claims about a company than the company itself.  BMO is quite reputable.  Their classification of condensate as "oil" is just a convenience since condensate and oil are both liquids and typically have similar pricing.  BMO's calling Rex's condensate "oil" is technically wrong, but a common convention.

When you see X barrels of NGLs, you don't know the mix of ethane, propane, butane, iso-butane, pentanes, and C5+s, you just make an assumption based upon what most wells produce.

Likewise, when you see a barrel of oil, you often don't know if it's light or heavy, sour or sweet, and the regional prices for the same barrel will vary by what the local refineries are best set up to process.

If you look at specific posted prices from the likes of Plains Marketing or Chevron, you'll see that a barrel of condensate is worth something very close to a barrel of oil in most regions.  I'm not sure how Jack Straw arrived at $60/bbl for condensate, but I'm not in marketing, so I'm not an authority.  However, my guess is that Jack's pricing for condensate is too low and that it trades very closely with light sweet crude pricing.

-rdj

Permalink Reply by Bluflame on September 27, 2012 at 7:51am

Ron,

  The difference between $60 and $90 per barrel for condensate is significant, in this case amounting to $8533/day. (1094 * .26 * ($90 - $60))  Again, let's hope you are correct!

BluFlame

Permalink Reply by Jack Straw on September 27, 2012 at 8:11am

RE: "If you look at specific posted prices from the likes of Plains Marketing or Chevron, you'll see that a barrel of condensate is worth something very close to a barrel of oil in most regions.  I'm not sure how Jack Straw arrived at $60/bbl for condensate, but I'm not in marketing, so I'm not an authority.  However, my guess is that Jack's pricing for condensate is too low and that it trades very closely with light sweet crude pricing."

Not so much a defense of my pricing, but an explanation:

I was attempting to provide a "current" price for the Ohio/PA region.

Insufficient infrastructure and local oversupply is seen to be a drag on local condensate and NGL pricing. Again, locally, I priced Condensate at about 2/3rds of historic relationship to WTI (West Texas Intermediate) Oil and I priced NGLs as about 2/3rds of their historic relationship to WTI. And as we all know, NG is very low (when compared to other fuels and currently low compared to some other regions).

I expect these regional differentials (particularly in our region) to moderate, as the infrastructure comes in place to allow a more efficient disposition.

As an example of a regional differential, in areas of primarily heavy oil production condensate might currently trade at a premium to WTI. This premium due to the ability to mix condensate with the heavy oil such that it flows through the pipeline system more readily and can be handled by a greater range of refineries.

My pricing estimates were truly "back of the envelope" and a snapshot in time.

My pessimistic pricing will hopefully represent a situation in flux.

I should note that my pricing is what an Operator might expect at the well head and does not represent the price it might achieve when transported by truck and rail to a refinery. I would expect the price differential to decline when transport can be by pipeline. 

All IMHO,

                  JS

 

 

Permalink Reply by Ron D. Jockefeller on September 27, 2012 at 8:28am

Thanks for that clarification, JS.  To maybe state the obvious, I wasn't throwing bricks at your pricing estimates (or at you).  Your posts are the best on this site.

I really don't have any idea what the local wellhead prices are currently, which are the relevant #s for landowners expecting royalty checks. The regional variations for raw and for refined products are enormous in the US and will be until infrastructure catches up with production. Between now and then pricing is going to move around a great deal.

It's funny to see some people hoping their leased acreage gets drilled right away (new Porsche), though they might get higher realized prices if it were drilled later (2 new Porsches, but not until 2016).  And underlying the assumption that discounts to benchmark pricing will be closed by new infrastructure is another assumption that pricing levels will be constant or trend upward over time.  They very well may trend downward, meaning you can get a 30% discount off $90 oil today or a 3% premium to $50 oil in 2 years.  (No that's not a prediction, just an example).

-rdj

Permalink Reply by Bluflame on September 27, 2012 at 8:37am

Ron, 

 In Jack's wife's case, not to mention two ironing boards!

BluFlame

Permalink Reply by Jack Straw on September 27, 2012 at 5:14pm

RE: "It's funny to see some people hoping their leased acreage gets drilled right away (new Porsche), though they might get higher realized prices if it were drilled later (2 new Porsches, but not until 2016)."

Like you, I would hate to see that "flush" gas and associated liquids sell at today's low prices. Not sure as to whether it will require a wait until 2016 .... might only await 2014 .... but then again, it might be 2018.

NG supply to demand might balance quicker than expected as that steep decline curve and movement of rigs out of the dry gas areas contrive to bring things more quickly in line - a cold winter would help.

The stampede from Coal to Natural Gas for the generation of electricity prevented a summer collapse of Natural Gas Prices (that $1.90/mcf in April really sucked). It is interesting to note that today's Henry Hub Spot price topped $3/mcf - this at the start of the fall shoulder season. I think that the Natural Gas storage builds for the next four weeks will be crucial in determining pricing over the next four months.

Some of that substitution from Coal to Natural Gas is doubtless permanent; but, it is my opinion that once Natural Gas hits around the $5/mcf mark Coal will become more popular and at the same time O&G operators will start moving rigs back into the Marcellus dry gas areas. I fear that Natural Gas may be range limited between $3 and $6/mcf for quite some time, as it yo-yos back and forth.

LNG exports (should they be politically palatable) are at least four or five years in the future, assuming that they can get financing (they would not get any of my money). Tough to justify substantial investment based on a commodity long known for its instability of price.

I have followed Natural Gas prices (with interest) for more than forty years. During that (long) time, I have learned one thing .... I don't know jack.

 

All IMHO,

                JS

 

Permalink Reply by Ron D. Jockefeller on September 27, 2012 at 5:19pm

I so agree on trying to predict gas (and oil) prices.  They are even less predictable than women.

I think Powder River Basin coal becomes the cheaper alternative when natural gas gets to $3.50.  I'm not expecting to see natural gas prices above $4.25 for a LONG time.

There's going to be a lot of talk about LNG, but I doubt it will ever be more than a Bcf/d or two.

-rdj

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