September 28, 2012: elsewhere
they are talking about the decline in the number of active rigs in
North Dakota. It was opined that when a major operator is down to four
(4) rigs in North Dakota, "peak drilling" is in the past. That "major
operator" has never had more seven rigs in North Dakota (during the
current boom) and even back in February, 2011, had
plans to cut back to five,
and decrease the number of frack teams to two. The number of active
rigs in North Dakota has decreased, but I'm not sure the number of wells
completed/month has decreased. Investors should see some nice reports
going forward: the price of oil is trending up and drillers are
producing more oil in North Dakota WITH fewer rigs. The "Bakken rigs"
are (much?) more expensive than the traditional rigs, it should be
noted.
September 26, 2012: enquiring minds remind us
that a second (or third or fourth or ...) lease is not needed on
acreage where there is already a producing well (don't take this out of
context; there are exceptions). However, that's not the reason for the
post. A comment is made at the link regarding "perjury." Pretty strong
words. It references the argument of large spacing units vs small
spacing units. A review of the dockets suggest that Bakken spacing units
are growing in size, not getting smaller. I am not yet aware of more
than a handful of Bakken spacing units getting smaller (and they may
have been small to begin with). It will be interesting to see if
existing1280-acre units (or existing 640- or 2560-acre units are broken
into smaller spacing units going forward). MDW will be watching.
September 18, 2012: Tami, elsewhere,
is wondering "where Continental Resources, in relation to a Newfield
well, came from." Okay. See my note of August 20, 2012, below.
Continental Resources is one of the biggest operators in the Bakken, and
is one of the leading promoters of the Bakken. CLR recently acquired
some Newfield acreage (including the wells). MDW posted this:
Press release, Oct, 2011: acquired 22,600 net acres --> 923,270; from NFX for $275 million (small production; 8 drilled/unfracked wells) at: http://themilliondollarway.blogspot.com/2010/10/areas-of-interest-in-bakken-by-producer.html. It's too bad some sites make this blog off-limits. This blog is considered "nonsense" by some. Whatever.
September 18, 2012: elsewhere they are talking about Mountainview Energy; a
quick glance here might help.
September 18, 2012: see my August 20, 2012, note below. I am glad to see that
he found the answer on his own,
but, again, come on, guys, we've been blogging about the Bakken for a
couple of years now, and the boom is at least five years along in the
North Dakota Bakken, maybe 12 years along in the Montana Bakken. There's
no such thing as a dumb question, but some questions have been answered
so many times, ...
September 14, 2012: inquiring minds had questions about a well, permit/file # 19468.
It was opined that the pump was put on in August, 2011. In fact, one
can tell that the pump was more likely placed in January/February, 2012,
time frame. In August, the well was off-line only 6 days, hardly enough
time to put in a pump. On the other hand, in January/February, the pump
was off-line 39 days in January/February, 2012, the time consistent
with putting in a pump. In addition, the data provided by the NDIC
confirms that the status of the well, "AL," was 2/7/12 -- February 7,
2012. This data was all available to the individual answering the
question. [Update, September 16, 2012: I see that after I pointed out
the obvious error, Elwood provided a much better (and no doubt, correct)
response. I'm not sure about the comments regarding production decline
due to a new well, but Elwood is probably correct.
August 30, 2012: elsewhere an interesting question was asked:
does the size of the flare correlate with oil production?
This is my understanding. The flare may correlate with the initial
production but does not correlate with ultimate recovery (over the life
of the well). Think of natural gas as the bubbles in a bottle of
Coca-Cola, with the liquid being the crude oil. When the top of the
Coca-Cola bottle is opened quickly, the liquid spurts out, being carried
out by the bubbles. If one opens the cap very slowly, and/or if the
Coca-Cola goes "flat" for any reason, the liquid will not come spurting
out. Regardless of whether there are bubbles or not in your bottle of
Coca-Cola, all things being equal, the amount of liquid is the same.
August 25, 2012: elsewhere "Burke" wants to know about 163-100-7.
This would be permit/file number #22516. It is a St Mary well still on
confidential; based on other wells in this area, this well will most
likely be a long lateral going north into sections 7 and 6, Colgan oil
field. If so, it is already in production, with 1,998 bbls run in June,
2012. Runs were first recorded in May, 2012.
[Update: November 22, 2012: this is a Three Forks well; t7/12; cum 43K 9/12; -- not bad for a well this far north.]
August 23, 2012: elsewhere "Platestealer" is asking about a Hess 6-well pad. Here the results are, updated through more recent reporting period.
For
newbies, it should be noted that Eco-Pad is a copyrighted name by CLR
and refers to a CLR 4-well pad (I don't know if CLR limited it to a
number of wells, or simply a multi-well pad). But Hess is drilling
multi-well pads, not Eco-Pads, as far as I know. For more on CLR's
eco-pads,
click here.
August 23, 2012: elsewhere Andrew says Hess permits #19454 and #19452 are expired
but the NDIC site, today, says status of both permits are "LOC."
Nothing about being expired or canceled, according to "Get Well Scout
Ticket Data." The GIS map server does show the permits as expired. My
hunch is that the paperwork is in the mail. I've seen this before, but
maybe they have expired. #19456, RS-Ball-157-90-2227-1 was just
completed 6/12; with an IP of 197 (typical for Clear Water oil field).
#19457 on that same 5-well pad was also completed 6/12 with an IP of
149. [Update, September 15, 2012: "guppy" is correct -- the well files
have a statement by Hess that it wanted to renew the permits; the
request could easily be missed by the folks at NDIC.]
August 22, 2012: elsewhere they're wondering when #20557 comes off the confidential list.
That permit has been canceled (EOG, Liberty 24-2531W, Parshall); it
was canceled July 26, 2011 -- over a year ago. "Wormy" is usually on
top of things.
August 22, 2012: Clifford asks one of the best questions about wells regarding pumps. I don't think a lot of folks understand the concept to which he alludes. Great question; great observation.
August 21, 2012: see note below, dated August 20, 2012. Today we get this query: is there any explanation
why a certain well (#19731) produced only 3,350 bbls in June?
This
well produced 5,765 bbls of crude oil in June; the company sold 5,634
bbls of crude in June; and it produced 3,350 bbls of water. It's a nice
well.
August 20, 2012: this note will come off sounding a bit "catty," so I apologize in advance. It has to do with
this thread, linked.
I have no idea why folks have not learned to provide file numbers for
wells in question; names would be nice, but there are so many wells with
similar names that they can be confusing. In this case, neither the
name of the well, nor the file number was provided. So to get the data,
one has to go through a series of links/web pages to find the data. If
the file number had been given, the answer could have been arrived at a
whole lot sooner. I am not the only one who has mentioned this; it has
been mentioned by others, including "Karen" who did a great job for
years providing data for that discussion group but quit some time ago.
Despite all she provided for that discussion group, she was never
properly thanked, at least that I can recall. But I digress. Here's what
caught my attention and the reason for the post: I am amazed that
folks who have been receiving royalties for years from the Bakken and
follow various Bakken sites regularly still do not understand basic
difference between "production numbers" and "runs." In this case, yes
the well produced about 3,800 bbls of crude, but the company only sold
("runs") 3,400 bbls. For newbies, this would be expected; but for those
who have been receiving royalties for years and follow the Bakken on a
daily basis, come on. The boom started in Montana in 2000 and in North
Dakota in 2007, 12 and 5 years respectively now.
August 18, 2012: avoid this thread.
Unless I'm misreading the first two comments, some folks think the
Three Folks is "shallower" than the Bakken. I'm probably misreading it.
August 17, 2012: folks are talking about the Dublin oil field;
see questions asked. I tend to discuss things the way I would talk
about them if having lunch at the Economart in Williston. So, here's my
rambling thoughts. The Dublin field is one of hundreds of
designated/named fields in the Williston Basin of which the Bakken is a
part.
The Dublin field
has not been all that exciting, so getting $1,150/acre is not bad. I
would be happy with that. With electronic transfer, you should expect to
be paid within 30 days after signing the lease (I don't own mineral
rights; have never gotten a lease; have no personal experience, but
that's common sense. But the oil companies in the area are very, very
busy, and it could be much longer, I suppose before they get all the
paperwork complete.) Getting a lawyer involved is easier said than done,
especially when you live overseas, and I wouldn't worry about that.
Twenty (20) percent "royalty" is standard in the Bakken.
A
section is 640 acres, one mile square, or one square mile. Each side of
the section is one mile long. Spacing units are generally 1,280 acres
now. Companies are drilling one well into each spacing unit to hold the
lease. Once they have a producing well on a spacing unit, they hold the
spacing unit/the lease as long as the well is producing. Once they have
their first well, there is less urgency to drill more wells in that
unit.
Back of the envelope calculations: this is how
you calculate how many bbls of oil you "own" based on 20%/160
acres/1280-acre spacing. For every 1,000 bbls of oil that is taken out
of that 1280-acre spacing unit, you "control" 160 acres. So, 160/1280
--> 12.5 percent. However, you will receive only 20 percent of
that, or: 2.5%. So, for every 1,000 bbls of oil that is taken out of
the 1280-acre spacing unit, you would get 25 bbls. Assuming I did the
math correctly. I often make mathematical errors, so I welcome
corrections. If they net $75/bbl, you would get $1,875 for every 1,000
bbls from that well. Your royalty check will also include some payment
for dry natural gas and wet natural gas by-products coming up with the
oil.
Bakken wells have a horrendous decline rate. Even
if it's a great well, the production will drop off quickly. Early on, a
good well might produce 5,000 bbls/month, but over time, it will go down
to 300 bbls/month. Every well is different. Again, I am talking with
you as if I was talking over lunch. This is not legal information; it is
just idle chatter, and I would enjoy hearing other people's thoughts on
these numbers. If you explore this blog, other sites, you will get a
feeling for the Bakken and the production of a Bakken well.
In
the best Bakken, they will be drilling 8 wells/spacing unit. Zenergy
has already requested to put up to eight wells/spacing unit in Dublin
oil field. It will be a very long time before they get that many wells
in the Dublin oil field.
I will update the initial
production numbers (IPs) and the cumulative production of wells already
producing in the Dublin oil field area.
I assume you
have a 5-year lease; that is standard. The company has five years to
drill a well on your lease if that's true. They generally drill as soon
as possible. They need to get a permit from the state to drill; that has
not been accomplished yet as far as I can tell.
If
they get a permit, it will show up on the map at the NDIC website. Once
they get a permit, they generally start drilling within the year, but
not necessarily. Permits are good for one year, but they are easily
renewed on a yearly basis. The permit is between Crescent Point Energy
and North Dakota; nothing for you to be involved in.
Right now, it's simply wait and see.
August 13, 2012: a nice little discussion of a "pipe stem hole."
But that's not the reason I posted the link. I posted because they
mentioned a "workover rig." In the conference calls for 2Q12 earnings
for two different Bakken-centric operators, the issue of work over rigs
came up. It appears that, at least for one operator, a ratio of 1.5 work
over rigs to drilling rigs is their desired norm; that same operator or
another operator (I forget) indicated they were looking to find six (6)
more work over rigs.
August 6, 2012: I remember Rufus kicking me off the board some years ago because he thought I was "pumping" stock. Now, I see he is
linking the transcript of OXY's earnings conference call.
Interesting. It is particularly interesting he chose OXY: I recently
singled out OXY and its comments about the Bakken. But back to the
original point. "Milliondollarway" has nothing to do with investing; I
resisted incorporating information about investing on the blog, but it
was obvious that it was impossible to separate the Bakken from investing
if one wanted to learn as much as possible about the Bakken. I guess
others are starting to see that. After 12 years into the boom.
August 3, 2012: Five
years into the Bakken boom, "GJ" has noted that water is being brought
back to the surface when the well first starts producing (when the IP is
reported). The initial water that returns to the surface is mostly
the water used in fracking. After that initial regurgitation, water
brought to the surface is salty water, having nothing to do with the
water table (fresh water). That water brought to the surface is an
expense for oil companies to remove and place in salt water disposal
wells elsewhere in North Dakota.
August 1, 2012: in the August, 2012, NDIC dockets, there were several cases requesting new stratigraphic limits for the Bakken. I think
the first comment at the link is wrong but the discussion might be interesting to follow, assuming anyone else responds.
[Yes,
others responded, and as usual, Teegue posted an outstanding comment.
He brought up a couple of issues, one that has been problematic for
"newbies" like me for years. It was nice to find out that it wasn't just
me that was confused. For those interested in this subject, skip all
the chatter at the link (except for background) and go directly, do not
pass "go," to Teegue's comment.] [Later: it appears that a couple of
folks at the linked discussion group can post "water cooler" gossip even
if others cannot.]
July 26, 2012: a query about Hebron field; I've been curious myself.
[Later: now we now, see the August 22 - 23, 2012 dockets -- 18453, CLR, amend Hebron and/or Squires-Bakken; create 2 overlapping
1920-acre units, 6 hz wells on each (12 wells); create an overlapping
1920-acre unit, 1 well; create an overlapping 3840-acre unit, 4 wells;
create 2 overlapping 2560-acre units, 2 wells on each (4 wells); create
an overlapping 256-acre unit, 14 wells (not a typo); create 2
overlapping 2560-acre units, 12 wells on each (24 wells); create an
overlapping 2240-acre unit, 12 wells; a total of 71 wells?, Williams County;
July 20, 2012: price differences for the same Bakken oil; transportation, contracts, etc.
July 17, 2012: "
this is a WOW!" Llano -- with a
6,800-bbl IP.
[Yes, and that was a huge typo. I assume the intern has been fired.]
July 11, 2012: folks are talking about price of shipping by railroad.
June 24, 2012: this thread suggests another reason for a perceived backlog in fracking.
In some cases, it is possible that road restrictions or other reasons
are keeping frack crews from getting to a well. It's always something.
June 21, 2012: elsewhere
questions have been raised regarding four new wells on proposed
2560-acre spacing where two producing wells are located, each on
1280-acre spacing. This is an instructive case. I was hoping more
knowledgeable folks than I would weigh in; it would help newbies to
understand the Bakken. We are going to see a whole lot more of this.
[Update: Teegue has provided an outstanding answer to the question
raised at the linked thread. The justification provided by the drilled
for 2560-acre spacing had to do with the 400-foot off-sets from the
edges of the spacing unit (generally section lines). His answer also
provides an answer to an issue I've never understood: Zones. Great
answer. Needs to be read by all.] As long as the driller drills four
wells in a 2560-acre spacing unit, I do not see the downside of a
2560-acre spacing unit. Even three wells in a 2560-acre unit would be
better than one in a 1280-acre unit.
Issues and answers as I see them:
- wells are permitted for specific spacing units; those spacing units
stay with the wells. For example, 160-acre spacing for a Madison well
will remain 160-acre spacing even if a 1280-acre spaced Bakken well is
permitted. In this case, two CLR 1280-acre spaced wells are currently
producing. It appears the case is pending to determine the spacing, but
most likely four CLR wells will be permitted on 2560-acre spacing. If
so, it won't affect the spacing of the two wells currently producing.
- each horizontal will be a two-section lateral, but will be spaced
for four sections; in this case the four sections are all in a
north-south line. Anyone owning minerals in any of these four sections
will participate in all four wells. Theoretically, I guess, it's as good
as one well on 640-acre spacing.
- The writer worries about "poorer" sections to the north "diluting"
the value of the "better" sections to the south. Assuming that is an
accurate assessment of the "north sections" vis a vis the "south
sections," mineral owners don't have to worry about "dilution." They
participate in all the wells. Even if a mineral owner owned only 10
acres in the toe of the southernmost section, she would participate in
oil being produced from the toe of the northernmost section. Sweet.
That's how I see it. I could be wrong. Four wells
on 2560-acre spacing --> one well/640-acre spacing (all mineral
owners in all four sections participate in all wells). Obvious one
well/640 acres is better than one well/1280 acres. The four wells are
close together and they are CLR wells, so a 4-well Eco-Pad is possible,
but it looks like their will be two closely spaced pads based on the
NDIC GIS map, but I am quite unsure about that.
June 20, 2012: the folks over at the Bakken Shale Discussion Group have also noted the relationship between CLR and BR with regard to the Midnight Run wells.
June 17, 2012: Bakken oil millionaires are talking about their first paycheck, but look at those taxes. Wow!
June 14, 2012: Elsewhere "schmitty" mentions probate.
This is a great time to talk about probate and mineral rights. Do whatever it takes to get your property to whom you want it to go before you die.
If at all possible, don't let anything go through probate. Probate will
tie things up for quite some time but that's a minor problem compared
to the bigger problem. Having done title searches I can tell you it will
take hundreds of hours to sort out who owns what minerals, and for
lawyers those are billable hours. After three generations of North
Dakotans, oil rights have been spread out among thousands, and the
proportions have grown smaller and smaller. In many cases, one can
almost guarantee that any potential for mineral rights will be lost in
probate. You might as well assume most of your oil money will be lost in
probate if you area a small player. Many would recommend a family
trust.
June 14, 2012: Elsewhere it is being noted that operators are starting to put in three to four wells per section.
Allen provides a nice update on Newfield's second Charlotte well.
June 13, 2012: Elsewhere Tj is asking what is meant by open hold fracture completion.
Baker Hughes animation
June 13, 2012: Elsewhere I see Rufus is now following the stock market.
June 13, 2012: Elsewhere jbird is asking if there is an error in the legal description of two Hess wells.
There are no errors. These two wells are about 50 feet from each other
on a 2-well pad. One horizontal will jog over to the west a bit and run
north through sections 7 and 6. The other horizontal will go straight
north through sections 8 and 5. The two wells will parallel each other.
[Add, June 16, 2012: the linked discussion group is probably the
most-involved group of Bakken folks and yet the level of their questions
remind us how little so many folks know about the Bakken. Twelve years
into the Bakken boom, I find it incredible.]
June 11, 2012: Elsewhere Tj is asking where to find fracking data. I understand there may be several websites that have that data such as
FracFocus. The
source of course is the NDIC web site.
The "milliondollarwayblogspot" often posts fracking data taken from
multiple sources. The MDW blogspot is "searchable." It's best to search
by file/well/permit number.
June 10, 2012: file under "No Such Thing As A Dumb Question."
Elsewhere "Platestealer" is asking how many folks employed by the operator actually work on a rig. I was quite surprised by the excellent answer.
June 5, 2012: Elsewhere "Platestealer" is looking for a source for aerial photos. An excellent source for aerial photos is
Vern Whitten Gallery. Another source is
Robb Siverson. There may be other sources at this blog, but this is a start. (Here's another one:
Overland Aerial Photo which I missed but is also at the blog
at this link.)
June 4, 2012: Bazel wonders about the decline rate in the Bakken. Here are the cumulative of some of the wells noted:
- 19731, 1,800, BEXP, Irgens 27-34 1H, East Fork, Williams; t9/11; cum 59K 4/12;
- 20639, 2,901, BEXP, Judy 22-15 1H, East Fork, Williams; t9/11; cum 93K 4/12;
- 20640, 2,597, BEXP, Irgens 27-34 2H, East Fork, Williams; t9/11; cum 62K 4/12;
As Mark Twain was reputed to have said, I would rather have a
free-flowing IP of 5,000 bbls, than a 1/2" choke with 0 bbls. I don't
think investors are watching IPs as closely as mineral rights owners
are. See poll.
June 3, 2012: "
Eastern MT" elsewhere wants to know about #22374, Whiting's Quale.
A bit of the story can be found here. Whatever you do, don't mention the "Million Dollar Way."
As usual, Teegue provides some great information. Whenver Teegue posts, you can be sure he/she posts some good information.
May 29, 2012: CLR assumes some Newfield wells?
Here are
the wells.
It will be interesting to see if anyone answers the query. I am
surprised that after eight hours, no one has made a derogatory comment
about the blog that was mentioned in this query. About now I would
expect someone to say the blog that is mentioned is all nonsense. The
wells transferred from Newfield to CLR were
reported in the May 16, 2012, daily activity report.
It will be interesting to see if someone points that out in an answer
to the query. [June 1: it appears no one dares touch this query with a
9-foot pumping rod, not even Rufus.]
May 29, 2012: a bit chippy? Defensive, insecure, anti-investor class?
May 24, 2012: This is why the Geico "rock" commercial resonates --
at least one person thinks the NDIC is limiting drilling to one well per section.
We are five years into the boom. Thousands of news stories later and
thousands of posts elsewhere and we still see these comments.
May 19 2012: Elsewhere "Blackjack" is wondering what the difference is between "runs" and "production." See my
discussion of this subject here.
May 16, 2012: Elsewhere Craig is looking for a site that tracks historical data comparing "ND Sweet" and WTI. My "
Data Links" site has that information. It should be noted that the best site (
SemCrude) does not include a better comparison,
light Louisiana sweet (LLS), unless I missed it.
May 15, 2012: Elsewhere "Barney" has asked
an interesting question regarding the legend on the NDIC GIS map
server. His question is yet to be answered. If no answer is forthcoming
in the next couple of days, I will try to remember to take a stab at it.
May 12, 2012: Elsewhere "Gary" is asking
if #22882 and #22883 will be running from sections 21 to 14. We are now
into the fifth year of the Bakken boom, and I think the Bakken Shale
Discussion Group has been up almost that long. Gary's question provides a
bit of insight how far we've come in understanding the Bakken. To say
the least, that would be a long lateral. To answer the question, these
two wells will most likely parallel:
May 4, 2012: Elsewhere "Barney" asked how to find section-township of a well when only the name of the well is given.
The fastest way I know is to locate it on the NDIC GIS map server.
Simply go to the map server, click in "Find well" and type in just one
word of the well's name.
April 4, 2012: Elsewhere "blacksheep" asked if a well could be placed back on "confidential status" multiple times.
The answer is "yes," a well taken off the confidential list can be
placed back on it; it seldom happens, but I have seen examples. Teegue
says: "... it happens only when a recompletion is later attempted in a
different pool than the pool targeted in the drilling permit."
If that is accurate, Oasis must be going after a new pool with
the Clark well in the Tyrone oil field north of Williston.
Elsewhere "jbird" wants to know: has #20755, HA-Dahl-152-95-0706H-2 been fracked? This Hess Three Forks well in the Hawkeye field is still on DRL status.
From
the file report of the Dahl well: "During the lateral operations Hess
wanted to deviate to the east of the already drilled and producing
HA-Dahl 152-95-0706H-1 Middle Bakken lateral to investigate an anomaly
that appeared when seismic lines were run in the area. This area of
interest was thought to be a naturally prouced fracture zone in the
Three Forks Formation, with the possible fractures being caused by the
generation of hydrocarbons from within the Bakken Formation. Operations
geologists and engineers thought these natural fractures may help
increase the production from HA-Dahl-152-95-0706H-2 Three Forks well.
During the time when the well bore passed through the area in question
there were noticeable increases in total gas concentrations. On the
morning of 1/9/12 at ~ 0810 hours CST, a possible fracture was crossed
and a 4,600-unit gas show was recorded. This gas show was accompanied by
a flare that was ~ 50 feet in height. This gas was quickly circulated
out by the rig crew and drilling was resumed." [No mention was made
whether roughnecks had to change their underwear before continuing
work.] Several other formations were also evaluated as potential pay
zones.
See comment below: this well is about a mile west of another big well, the Mogen well. Go to this link for more information, and then look at the location on the GIS map server. This is huge.
"Scout" wants to know about #21378,
EOG's Wayzetta 124-3334H. That well is still on DRL status. [The whole
issue of "tight hole" status and "DRL" status" can be confusing. See
FAQs,
question 14: EOG typically waits until well is completed before it
places the well on "tight hole" status.] It was spud(ded) 10/2/11, so it
is also still within the six-month "tight hole" window. The
nomenclature, "124" is interesting. No doubt the "124" is simply
chronological numbering of the Wayzetta wells. In T153N-R90W, EOG has 53
wells/permits. Of these 53 permits, there are 39 Wayzetta wells; the
lowest number is #2 (if there is a #1, I missed it). The highest number
appears to be 157. That's a lot of Wayzetta wells planned. The earliest
Wayzetta permit is #16733 (now a salt water disposal well); the most
recent permit is #22704. The first Wayzetta well appears to have been
spudded in January, 2008:
- 16961, 1,064, EOG, Wayzetta 8-11H, short lateral, s1/08; t4/08; cum 377K bbls 2/12; producing about 3,000 bbls 2/12;
I haven't gone through the entire list yet, but the Wayzetta well with the most production to date, may be:
- 16991, 1,383, EOG, Wayzetta 9-03H, short lateral, s4/08; t7/08; cum 672K bbls 2/12; producing 7,000 bbls 2/12
Mark provides a nice short explanation how royalties work:
If
one owns/leases 10 acres in a 1280-acre unit, one will get 1/128th of
the royalty on the well. If you have a 3/16ths royalty on your lease,
your payment will be 1/128ths x 3/16ths, or 0.0014648 times the income
on the well, which means you get $0.14 for every barrel produced (at
$100/barrel). If the well produces 100 barrels a day, you will make
$14.00 per day. Note that these wells will typically decline fast, so
your initial payment will not be sustained. [That $100/bbl in the Bakken
is at the high end; contracted/hedged price may be $100, but spot price
is significantly less.]