Enervest is selling their holdings. I ask why? Perhaps production is not what they hoped
perhaps they got an offer they couldn't refuse.
Here is some info. What do you think?
Mike, your speculation is dead wrong. I know all of the Enervest/EVEP guys extremely well. I see them at least every other month. I talk to them at least every month. And I can assure you that they are EXTREMELY pleased with production.
Enervest/EVEP is not an E&P that "proves up" development acreage, which takes a big budget and expertise they do not possess and do not intend to acquire. Enervest/EVEP focuses on mature, low-decline assets. They acquire them inexpensively, improve them, drop them into their MLP, and pursue a very low risk/medium return strategy.
Developing a brand new shale play like the Utica is a high risk/extremely high reward proposition that requires very significant capital.
For MORE THAN A YEAR, Enervest/EVEP has been extremely clear about their intention to swap their Utica acreage for mature assets somewhere else in the country. They are likely to break it into pieces to maximize value, I'm told. And I expect some Asian bidders, though I would have thought Exxon the most likely entity to do an asset swap.
So one last time: Enervest/EVEP are delighted with Utica production, and they have been planning/talking about/working on their asset swap for over a year. The sale/swap is being run by their petroleum engineer, Ron Gadjica, who has had a data room open to prospective buyers/swappers for almost two months now.
Here is the most recent press release on Eneverst/EVEP's Utica well results. Ron has it right. Enervest has a lot of acreage that it stumbled into, prime acreage, but acreage that doesn't suit their expertise/business model.
HOUSTON, TX -- (Marketwire) -- 08/20/12 -- EV Energy Partners, L.P. (NASDAQ: EVEP) and EnerVest, Ltd., today announced initial production results for a second well in the Utica Shale and provided an update on the Frank 2H well.
The Cairns 5H well, located in Carroll County, Ohio, near the border with Tuscarawas County, flow tested at a 24-hour rate of 1,690 barrels of oil equivalent per day. The production mix was 729 barrels of 52-degree API condensate per day, 2.2 MMCF of natural gas per day and 587 barrels of natural gas liquids per day. This assumes processing of the wet gas flow stream with corresponding natural gas shrink and natural gas liquids yields. The well was drilled to a total measured depth of 12,693 feet with the horizontal section measuring 5,384 feet and completed with 19 stages. EVEP owns an approximate 43 percent working interest in the well, and an affiliate of EnerVest owns an approximate 50 percent working interest in the well.
Following shut-in to install artificial lift equipment, the Frank 2H well in Stark County, Ohio, produced into sales at an unassisted 24-hour rate of 870 barrels of oil equivalent per day. The production mix was 360 barrels of 47-degree API oil per day, 1.2 MMCF of natural gas per day and 312 barrels of natural gas liquids per day. This assumes processing of the wet gas flow stream with corresponding natural gas shrink and natural gas liquids yields. The Company anticipates activating the artificial lift within the next few weeks. EVEP owns an approximate 35 percent working interest in the well, and an affiliate of EnerVest owns an approximate 40 percent working interest in the well.
EV Energy Partners, L.P., is a master limited partnership engaged in acquiring, producing and developing oil and gas properties. More information about EVEP is available at http://www.evenergypartners.com.
(code #: EVEP/G)
This press release may include "forward-looking statements" as defined by the Securities and Exchange Commission. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the partnership expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by EVEP based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of EVEP, which may cause our actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to financial performance and results, availability of sufficient cash flow to pay distributions and execute our business plan, prices and demand for natural gas and oil, our ability to replace reserves and efficiently develop our current reserves and other important factors that could cause actual results to differ materially from those projected as described in the EVEP's reports filed with the Securities and Exchange Commission.
Any forward-looking statement speaks only as of the date on which such statement is made and EVEP undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.
EV Energy Partners, L.P., Houston Michael E. Mercer 713-651-1144 http://www.evenergypartners.com EnerVest, Ltd., Houston Ron Whitmire 713-495-6525
Source: EV Energy Partners, L.P.
Ron, I am knew to this shale stuff and am just trying to learn. I have land that enervest and chesapeake are jointly holding my lease. I have read in the carroll county group that the royalties the landowners are getting are very small compared to what they were told to expect. In most cases royalties were in the $600 an acre per month range for the first month and then dropped dramatically the next month to about the $300 range and then dropped to the $200 dollar range the next month. I am not trying to speculate but don't these numbers show a very sharp decline in production. Is this what was expected? Also you said Enervest has no interest in developing a new play because it is very risky. My question is where is the biggest risk? Is it in the actual drilling and fracing of the wells or is it in the chance that production might not be as good as hoped? Thanks for the info, much appreciated
Mike, I don't know about the carroll county group. If you paste the name of the well into this thread I can take a look at the well production and let you know if the well is underperforming expectations or not. I would add that early in the development of a new shale play, expectations are all over the map and the producers are still experimenting with drilling and completion techniques.
As for the drop off in production, that's perfectly normal. This is a pretty typical decline curve:
Note that about 15 months in, the production has dropped 80%. The scale on the vertical axis is logarithmic instead of linear, so look at the numbers there carefully.
The biggest risk in developing a new play is spending a lot of money and getting no economic return. The capital spend for developing energy assets is enormous. Drilling and fracking is hard in the first few years of development of a play because mistakes can lead to lower production, and there's not enough data about the geology to NOT make mistakes. It's mostly guesswork at first. And yes, there is a chance that production might not be very good, even if one does a technically perfect job - that happened to Devon in Ashland and Medina (although I would argue they made a mistake to even lease that acreage).
The initial production numbers for the Cairns 5H and Frank 2H well are really good. If you run the numbers using current market prices for the commodities, the annual revenue is pretty impressive even considering the decline rate noted by our colleague Ron D. Jockefeller (love the moniker!). Enervest & CHK will get a quick return on these wells.
Lessor royalties are another matter with an entirely different set of variables such as royalty rate, gross or net terms, number of acres in the drilling unit, etc. The first two variables are lease-related, while the third is entirely controlled by the driller. Since Carroll County was leased early in the Utica feeding frenzy before much was known, I'm speculating royalty rates were low (12.5%?) and lease terms were poor (net?). Note that these wells are "5H" and "2H", implying that several wells will likely be drilled from the same pad. As a lessor in a drilling unit, you share in the revenue from all wells drilled in the unit on an equal basis. The drilling units vary in size, but can be as large as 1280 acres. The net effect of the multiple wells within the same unit is to stagger royalty payments over several wells drilled over several years, not a bad deal. Kind of saves you from yourself!
So, you need to know a lot more information before you can make an accurate assessment of the $600-$200/acre/month you've seen reported on the Carroll County GMS site. BTW..I do not monitor the Carroll County site.
Good luck! The good news for you is that CHK is drilling like mad in Carroll County. CHK & Enervest have a long-standing close relationship. Their CEO's gave a joint presentation to the Ohio Oil & Gas Association in the summer of 2011, where Aubrey McClendon of CHK made his now famous pronouncement, "The Utica Shale is the best thing to happen to Ohio since, maybe, the plow!". Looks like he may have been correct!
Tracker Lario LLC bought up all leases of Enervest in Palmyra, Paris, and Newton Townships...
A landowner in Carroll county posted this about their royalties. This person signed at 17.5% gross.
"I own 62.6 a of a 184.170 A unit.
Three checks so far, I know the production figures for the next two.
First check was $624.75 per acre per MONTH.
Second check was $381.32 per acre per month.
Third check was $245.90 per acre per MONTH. yes, per month not per day!!
the next check at the end of this month (August) for June production will be nearly the same as last month's check.
the following one for July production is looking to be about one half of May and June production."
Is this gonna be about the average?
RE: "Is this gonna be about the average?"
If you scroll back a few posts, you can make note of the decline curve posted by Ron D. Jockefeller that is typical for shale wells.
The bad news - the decline curve is initially steep.
The good news - over the years, the decline curve flattens out, with the promise of many years of production.
Royalties (obviously) depend upon royalty percentage, how many wells in a unit, how many feet of well bore are exposed to the producing shale, a particular landowner's percentage participation in the unit, is it wet gas or dry gas (if wet gas, what percentage of NGLs), initial production and where they are on the decline curve.
And importantly - what is dry gas selling for and (if pertinent) what are NGLs selling for.
Right now, both Natural Gas and NGLs are selling at very low prices - it is not inconceivable that both could double in price over the next year.
Back to your question "Is this gonna be about the average?" - not likely, every well and every situation will be different. The "average" can only be obtained in hindsight, and we are much to early in the first half of the first inning to know - it might be possible to answer your question in ten years time. We would all like to know the answer to your question - and how it might affect us personally - but I am afraid that only time will tell.
Were we able to provide an "average", it is likely that the variance from the average will be so great as to make the "average" a fairly meaningless figure.
To Jack Straw's list of unknown variables in the example, let me add that we do not know if the owner is a sole owner of the property or whether there are partners.
Using initial production numbers from the Enervest 5H well posted earlier coupled with "current" commodity prices and the unit size/ownership acreage/royalty rate/gross terms in the example, the royalty calculation COULD be as follows:
729 brls/day X $97/brl= $70,713/day
2,200 MCF/day X $3/MCF=$6,600/day
587 brls/day X $35/brl=$20,545/day
Estimated royalty/month (assuming 34% of unit and 17.5% royalty and 30 days/month, and sole ownership of the acreage)
$195,176 X .34 X .175 X 30 = $348,389/month
Royalty/month assuming 80% production decline after one year
$348,389 X .20 = $69,677/month
The post-decline number is within reason of $624/acre/month. ($624/acre /month X 62.5 acres= $39,109/month) After all, the initial production number will fall quickly. I could squeak by on this royalty!
Am I missing something???