Quarterly ND Lease Sale

The results of the quarterly North Dakota state lease sale for May 4 - 5, 2010, have been posted.

Highlights:

The highest lease/acre: an eight-acre tract in Stark County drew the highest price: $12,500 per acre.  This was in section 24, T140N-99W. It is not located in a designated field. Of interest, Whiting has a rig on site on mile north in section 13, T140N-99W, #18837, Kubas 11-13TFH. 

Mountrail County (one example per category per county)
Highest bonus/acre: $7,200/acre for a 20-mineral acre lease (Marshall & Winston Inc)
Single largest lease: 160 mineral acres @ $6,200/acre = $992,000. (Northern Energy Corp)

Williams County (one example per category per county)

Highest bonus/acre: $7,100/acre for a 40-mineral acre lease (Sundance Oil and Gas LLC)

Single largest lease: 160 mineral acres @ $6,700/acre = $1,072,000. (Sundance Oil and Gas LLC)

McKenzie County (one example per category per county)

Highest bonus/acre: $5,500/acre for a 160-mineral acre lease (B J Kadrmas Inc)

Single largest lease: 160 mineral acres @ $5,500/acre = $880,000. (B J Kadrmas Inc)

Dunn County (one example per category per county)

Highest bonus/acre: $5,500/acre for a 137-mineral acre lease (Northern Energy Corp)

Single largest lease: 137 mineral acres @ $5,500/acre = $753,500. (B J Kadrmas Inc)

*****

Mountrail County
The high bid ($7,200/acre) in Mountrail County was section 21, T150N-92W, Van Hook oil field. 
The largest single bid, the $992,000 bid, in Mountrail county was in section 27, T150N-92W, a wildcat, but right next to (south of) the Van Hook oil field.


Williams County

The high bid ($7,100/acre) in Williams County was section 33, T156N-103W, Bull Butte oil field, just north of Squires oil field. 

The largest single bid, the $1,072,000 bid, in Williams County was in section 26, T156N-102W, a wildcat just north of Squires oil field. 

Dunn County

There were only five (5) tracts in Dunn County leased; they were all under the Missouri River, wildcats just south of Van Hook oil field. 

McKenzie County
The high bids in McKenzie County were in an undeveloped, undesignated area just 1.4 miles northwest of Alexander, just a 1.5 miles west of US Highway 85, just before driving into Alexander. 

*****

A 160-acre parcel is one-fourth of a section (640 acres). On 640-acre spacing, one can put in a short lateral. A 160-acre parcel for $1 million equates to $4 million for the entire section. The short lateral well could cost about $6 million. So, just to get started, the upfront cost for a well going into this section could cost $10 million. 

CLR: EUR To Be Increased by 20%

Continental Resources/CEO increases estimated ultimate recovery by 20%, from 430,000 to 518,000 boe per well. Note: EOG has EUR of 700,000/section in its very, very good Parshall wells. Dual laterals are said to increase EUR from each section by 400,000 boe if I remember correctly.

With new technology and lessons learned, this does not surprise me in the least.

USGS survey in 2008 (or analysts following the survey) suggested 2 - 4% of total Bakken reserves recoverable; since then some folks suggesting they are bringing up as much as 7%.

Remember: going from 2% to 4% is doubling the total number of barrels.  Two percent doesn't sound like much; doubling sounds huge. It is.

Reuters: CLR "Handily" Beats Street

Full report here and Yahoo!Finance story here.

Huge: total oil and natural gas sales rose 134%.
Huge: Bakken production more than doubled.

And CLR's activity in the Bakken has just begun.  The current boom got going in 2007 and is still in the growth stage.

Enbridge: Strong 1Q 2010

Earnings Call Transcript

Financials

• Adjusted earnings increased 19% to $318 million
• Beats by 7 cents; confirms guidance

Operations

• Alberta Clipper brought into service April 1, 2010, on-time/on-budget
• To develop a 99-MW wind energy project

Four areas of operations

• Alberta regional oil sands
• Ultra deep offshore oil and gas
• North American oil and gas shale
• Renewable and green energy

Conference call references the expansion in North Dakota; went on-line on January 1, 2010, and already maxing out at 51,000 barrel daily capacity

Unless I missed it, not one question about wind or green energy. I think everyone understands why ENB is getting into wind energy

Change in Active Rigs Status

Normally I see the number of active rigs move up or down one rig, maybe two rigs, at a time. One day it's 110, the next day, 109, a couple days later 110, again. But generally, one rig one way or the other.  Last week we moved up from 111 to 114 fairly quickly (setting a new record), but now in the past couple of days, the number of active rigs in North Dakota has come down quite quickly, one/day and sometimes two/day. 

Right now it's back down to 109. Maybe it's just a coincidence that we've come down this fast, but one has to wonder if something is going on.

I can think of three things: a) backlog in fracking; b) price of oil in flux; and, c) rigs moving into Montana.  I really doubt (b) -- despite fact that oil has come down a fair amount in past couple of days, everything points to trending higher. Granted, there has been more talk of China / global recovery slowing down but I just can't see oil companies reacting this quickly. So, although I reference price of oil, I don't think that's the reason for sudden drop in active rigs.

There is some chatter about increased activity in Montana and that's my first choice to explain fewer rigs in North Dakota. If so, that's not a big problem; the entire Williston Basin gains.

I don't know enough about the oil industry to comment on possibility (a) -- the backlog in fracking. But, as I've said before, it seems like it would be expensive to drill a well and not complete it because of backlog in fracking. One has the cash flow to pay the drillers and not yet getting return on oil production. Maybe drillers are reversing the way they schedule things. In the past, they scheduled drilling, and then scheduled fracking, only to be put on a waiting list.

Maybe they are not scheduling fracking, and once they are "penciled in," they spud four to six weeks before fracking crew is to arrive. Of course, if it's necessary to hold a lease, they will drill regardless.

And maybe it's just pure coincidence so many wells have gone inactive in the past few days.

Slawson's Banshee 2-1H

I have to credit someone else with bringing this to my attention. I was so busy updating the NDIC hearing dockets for May that I didn't take time to look at the reports of newly reporting wells.

Take a look at Slawson's Banshee 2-1H well in the Sanish. It's IP was an impressive 1,306 bopd, but more impressive is the consistency of the first few months of production (figures rounded):

• December, 2009, first 22 days: 23k
• Janaury, 2010, full month: 22k
• February, 2010, full month: 17k
• March, 2010, full month: 19k

The total cumulative is 81k in less than four months. Some of the drillers are getting $74 at the wellhead; if so, this well produced almost $6M so far. It will be interesting to see cumulative production one full year from now.

Hopefully Slawson partnered with a public company so we might get some information on this well, particularly number of frac stages. Also, note that Banshee 1-1H is located just a few feet to the west in the same section. It would be interesting to know if both wells are in the same formation. If not, it validates my thinking that fracking only reaches out about 400 feet. We'll see. [Update: the Banshee 1-1H had an IP of 1,117. This suggests to me that fracking does not extend very far out.]

Interestingly, this was a short lateral, and spudding was the last day in October, so this was fast -- the month of November drilling, followed by fracking, and here we are.

The Banshee 2-1H is located right on the border of the Sanish and the Parshall (just inside the Sanish, but practically a Parshall well). It is also right on the section line separating T153N-91W and T154N-91W. Both townships are very active and very productive.

There are two rigs on site in T154N-91W and a string of nine (9) confidential wells running right up and down the center of this township.

Likewise, there are two rigs on site in T153N-91W, and a third well being drilled (just starting) and a fourth well almost complete. There are also four (4) new permits in this township and eight (8) wells remain on the confidential list. All of the wells in the township that are off the confidential list are long laterals except for the Banshee and three others in sections 1 and 2.

NDIC Hearing Dockets for May, 2010, Posted

An abbreviated summary for the NDIC hearing dockets scheduled for May, 2010, has been posted. Again, this is for my own use, and there may be typographical errors. For the official dockets, go to the NDIC website.

SM (St Mary) Energy

Earnings

• 4Q10
• 3Q10
• 1Q10

December, 2010 Corporate Presentation 

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Feature Article In Oil And Gas Investor, August 2, 2014

Doubling Down On Divide County: SM Energy Bets on More Aces in Bakken Frontier

Link here.

SM Energy Co.’s buyout of Baytex Energy Corp. in North Dakota further demonstrates Bakken and Three Forks producers’ confidence in what had been considered the play’s frontier—Divide County.

A neighbor to SM’s and Baytex’s leasehold in SM’s “Gooseneck” play area in central Divide County is Denver-based American Eagle Energy Corp. “The perception of Divide County had been that it is not as good a performer,” Tom Lantz, American Eagle chief operating officer, said in Oil and Gas Investor’s April 2014 cover story, “The Williston Basin.” “The reason is that the reservoir in our area is normally pressured, while it is over-pressured in the deeper part of the basin. That pressure is what drives those spectacular initial rates you are used to seeing there.”

But the Bakken and Three Forks are at a shallower depth—about 8,000 feet—in Divide County, rather than at about 11,000 feet in the center of the Williston Basin in McKenzie County to the south, so the cost of drilling is less, Lantz said.

Also, because it is shallower and under less weight, less-expensive sand appears to work fine as proppant, rather than ceramic. Ultimate recovery is some 450,000 barrels of oil equivalent (BOE) per well landed in Three Forks and 350,000 BOE from wells landed in Bakken in American Eagle’s leasehold—less than the more than 600,000 BOE proved by wells in the basin’s center. But, Lantz said, American Eagle’s Divide County wells cost some $6 million rather than $9 million. “The economics are very good.”

Houston-based SM’s $330.5-million offer for Baytex’s North Dakota position involves 89, producing, operated wells, all in Divide County except for five in Williams County. SM will gain 61,000 net acres in the two counties, primarily in Divide and 70% held by production. Four additional Baytex wells are in confidential status and an additional five are being drilled, according to state records. Baytex has permits for five more wells not yet spud.

Calgary-based Baytex began drilling in North Dakota in October 2009. The deal will bring SM’s Bakken and Three Forks production from 16,500 barrels of oil equivalent a day to 19,700, 91% oil. The deal is to close in this quarter. SM will gain proved and probable reserves of 53.5 million BOE.

In the Gooseneck area, Baytex’s leasehold is in the middle and east of the SM position and is to bring SM’s exposure to this Three Forks play—with potential upside from successful completions in the overlying Bakken as well—to 97,000 net acres.

SM has been testing completions in Gooseneck with more sand per foot of horizontal wellbore. For example, on a roughly 10,000-foot lateral, SM had used some 192 pounds of sand per foot, the company reports; the new completion uses 265 pounds per foot. For the same length of lateral and when factoring in SM’s savings from a program toward reducing drilling days, the old well cost about $7 million; the new well, $6.2 million, it reports. Peak production from the new well is about 440 BOE a day; the old well, about 330. In short, the company reports, sand per foot has grown 38% and peak production has grown 33%.

News

May 17, 2017: postpones decision to sell assets in Divide County due to poor market conditions (SM Energy has elected to leave North Dakota; to focus on Eagle Ford)

January 7, 2015: SM Energy announces it will exit mid-Continent (Oklahoma); close Tulsa office; concentrate on core assets in the Bakken and the Eagle Ford. 

May 12, 2014: mentions that it has sold non-core Bakken assets; may be down to 159,000 net acres in the Bakken. 

April 5, 2012: update on SM wells in Poe oil field.

March 12, 2012: update on SM and Stark County.

February 1, 2011: SeekingAlpha on SM: well-positioned.

January 31, 2011: SM raised $350 million through senior notes; originally was to be $250 million. 

January 25, 2011: Preliminary production and proved reserve estimates for 2010

• Increased Bakken/TFS by 40% on sequential basis (4Q over 3Q)
• Replaced nearly 350% of its production through drilling

January 24, 2011: SM to raise $250 million through senior notes.
December 23, 2011: SeekingAlpha/Zack's rating on SM.

Original Posting

Strong earnings report for 1Q10

Net income for first quarter, 2010, was $126 million ($1.96/share) vs a net loss of $88 million ($1.41/share) for the same period one year ago.

St Mary's average realized sale price for oil/gas was $72.73/$6.15 this past quarter vs $34.40/$4.00 one year ago.

Daily production of oil actually decreased seven (7) percent, from 18 million bopd to 17 million bopd, year over year.

Yesterday I noted the "marketing expense" associated with EOG and its five-fold increase year-over-year. So, what did St Mary report for marketing? On the revenue side, marketing revenue almost doubled from $14 million to $23 million. Interestingly enough, that was offset by an equal amount in marketing expense: $13 million same period one year ago, and $22 million first quarter this year.

However, much of St Mary's gain came from selling non-core assets for a one-time gain of $121 million. Without that $121 million gain, this year's first quarter income would have been $239 million, but again, better than last year's revenue of $199 million.

With regard to NDIC hearing dockets, St Mary is more active than usual this month (May) compared to past several months. St Mary had nothing before the commission in March and April, but did have some cases in February.