Expiring Leases -- DNR As Third Example -- Bakken, North Dakota

The scuttlebutt is that expiring leases could appreciate 10-fold in the Bakken at the end of this year.

Now that annual reports are out, one might be able to find out to what extent one's favorite company is at risk with regard to expiring leases.

Unlike CLR and OAS, Denbury (DNR) does not break out the exact number of net mineral acres that could be lost at the end of the year if not producing.

DNR breaks it out by percent, and does not break out individual areas. Instead, DNR simply reports that 31% (in 2011), 20% (in 2012), and 13% in (2013) are subject to loss if not producing, and that is for their entire Rocky Mountain prospect.

DNR reports that it has 275,000 net acres in the Bakken. Applying those percentages across the board (which is subject to all kinds of problems, but nonetheless, that's all we have), DNR is subject to lose the follow number of net acres in the Williston Basin Bakken if not leased by the end of December of the corresponding year (numbers rounded):

• 2011: 85,000 acres
• 2012: 55,000 acres
• 2013: 36,000 acres

DNR currently has a 5-rig drilling program. (Before the merger with Encore, DNR had a 2-rig drilling program in the Bakken.) Therefore:

• 2011: 85,000 / 1280-acre units = 66 wells for 5 rigs --- more than 12 wells/rig
• 2012: 55,000 / 1280-acre units = 42 wells for 5 rigs 
• 2013: 36,000 / 1280-acre units = 28 wells for 5 rigs

Compared to CLR, DNR has significantly more acres/rig at risk, if assumptions are correct. But it does not appear to be excessive.

After completing these statistics for three companies (OAS, CLR, and, now, DNR) it appears there is a lot of talk about losing leases due to lack of activity but it appears that these companies are well positioned.

I wonder if a company with a unique business model (NOG) that has less control over its future, is at more risk of losing leases. NOG counts on other operators drilling on their leased acreage.


For CLR's expiring net leases, click here.
For OAS's expiring net leases, click here.

Another Man-Camp Proposed in the Bakken, North Dakota, USA

Link here (regional links break early and break often).

The proposed man camp would be about seven miles southwest of Dickinson, and serve 100 - 400 men.

If approved, it would be the first man-camp in Stark County.

Whiting has increased its interest in Stark County, and in February, 2011, Empire Oil paid the state $9,600/acre for 460 mineral acres in Stark County, in the Elidah field, and probably to target the Tyler formation.

Expiring Leases -- CLR As Second Example -- Bakken, North Dakota, USA

The scuttlebutt is that expiring leases could appreciate 10-fold in the Bakken at the end of this year.

Now that annual reports are out, one might be able to find out to what extent one's favorite company is at risk with regard to expiring leases.

CLR has the following amount of Williston Basin leases expiring as of December 31 of the corresponding year (numbers are rounded):

• 2011: 100,000 net acres
• 2012: 124,000 net acres
• 2013: 214,000 net acres

CLR has about 24 rigs in the Williston Basin (22 in ND and 2 in MT)

• 100,000 / 1280-acre spacing = 78 wells / 24 rigs -->  3 wells/rig/year -- obviously not a problem
• Unless my calculations are wrong, or I have incorrect data to begin with, CLR has plenty of capacity

Compare with Oasis' expiring leases.
Compare with DNR's expiring leases.

Expiring Leases -- Oasis As First Example -- Bakken, North Dakota, USA

The scuttlebutt is that expiring leases could appreciate 10-fold in the Bakken at the end of this year.

Now that annual reports are out, one might be able to find out to what extent one's favorite company is at risk with regard to expiring leases.

On page 38 of the printed copy of the Oasis annual report, and on page 44 of the 130-page electronic copy of the Oasis annual report, this:

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire (numbers are rounded).

• As of December 31, 2011: 54,000 net acres will expire
• As of December 31, 2012: 24,000 net acres will expire
• As of December 31, 2013: 42,000 net acres will expire

Oasis notes that the cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire ("top leases"). 

How much did expiring leases cost Oasis in past years? Non-cash impairment charges, as follows:

• 2010: $12 million
• 2009: $5 million
• 2008: $1.6 million

Back-of-the-envelope calculations: 54,000 / 1280-acre spacing --> 42 wells. In addition, Oasis might have other wells that they might want to get to first. Regardless, they have 7 rigs and that works out to 6 wells for each rig this year. There is some discussion regarding this issue, but there is some suggestion that a lease will be held if the pad is at least started; others will take issue with this.

Request for Assistance

I don't have time to check every annual report of Bakken companies, so maybe others could help. If you have a favorite Bakken company, and have a copy of their annual report (electronic copies are available at this site; see top of sidebar at the right), see if you can find the numbers and send them to me via comments or e-mail. Please include page of the report, so I can verify or add clarifying statements.

Compare with CLR's expiring leases.
Compare with DNR's expiring leases. 

Investment Guide to the Natural Gas Industry

Eric Fox over at Investopedia.com recently posted a nice investment guide to the natural gas industry.

This guide will be linked at the natural gas tab (NG) at the top of this blog. 

$9,000/Acre -- Zenith Oil Field -- Tyler Formation (?) -- North Dakota, USA

Updates

April 5, 2011: Yesterday evening, the Stark County Zoning Board approved rezoning a 30-acre parcel of land to industrial from agricultural at Whiting's request.

Approved: A request by Whiting Oil and Gas Corp. to rezone about 30 acres from agricultural to industrial for an oil terminal site, temporary liquid site and a fresh water storage site.

As noted below, Zenith oil field is in Stark County, and the $9,000/acre tracts are just 10 miles west of Dickinson.

As a reminder:

The Tyler formation, according to the NDIC director Lynn Helms, extends well past the North Dakota borders, west into Montana and south into South Dakota. Based on stratigraphic maps, the Tyler formation may be even thicker than the Bakken in some areas. If you are interested in looking at the Tyler formation, simply "google" it. You will be surprised by the number of hits. The Tyler has accounted for about one percent of all oil produced by North Dakota to date; until recently, the Bakken had accounted for about six percent of all oil produced by North Dakota since 1951.

Original Post

The results of the February 21, 2011, North Dakota land lease sales were quite uneventful except for four tracts of land in Stark County which were acquired for the bonus price of $9,000 acre, clearly one of the highest bonuses paid in recent history, and I would wager to say, the highest bonus paid for non-Bakken interests. [Update: I lost that wager. I notice that at the North Dakota state land lease in May, 2010, Summit Resources paid a $12,500 bonus/acre for an 8-acre tract in the very same area -- section 24-140-99. Also, note: these are bonuses of public record. I have no idea what private individuals may be getting.]

Because this $9,000/acre has no conflicting details, such as other producing wells or other assets, this may be the new record paid for a mineral acre in North Dakota.

This is what I posted earlier:

Stark County:

• This is the county where WLL has recent interest
• Many tracts sold; almost all acquired by Clear Creek Resources, LLC
• Almost all under $500/acre; a couple for $800/acre
• With one huge exception: Empire Oil paid $9,000/acre for five separate tracts (four 80-acre tracts; one 60-acre tract); sections 23/26-140-99 and section 1-139-99. These tracts are in the Zenith field, and there is absolutely nothing on the GIS map server from the current boom that would give any hint of the reason why these tracts sold for this amount. A Tyler-pool vertical well spudded in 1984 produced 120K over its lifetime; a Tyler-pool vertical spudded in 1981 produced 116K over its lifetime; and (this might be the reason), the Tyler-pool vertical well spudded in 1984 has produced 608,562 bbls to date and it is still producing at 2,000 bbls a month, and no decline for the past several years -- in fact, it has increased over the past few years.

Specifically,

• 10752, New Millennium Resources, Inc. (current operator), Polanchek 8-34, spudded 5/84, is a vertical well targeting the Tyler A formation (which I believe is synonymous or similar to  the Heath formation). Total depth was 8,285 feet (about the depth of the vertical portion of a Bakken well), no horizontal, and had a huge IP of 323 for a vertical Tyler well.

This well continues to produce at 2,000 bbls/month. To date (as of 2/11) it has produced over 600,000 barrels of oil. Although the price of oil has averaged well under $75/bbl the last 26 years, if it had, this well would have generated $46 million. This shows the potential of wells in North Dakota.  The production is one thing, but the longevity is something else: 27 years this May, 2011. In addition, up until 2002, it was producing about 800 bbls/month. Starting in 2009, it was producing 2,000 bbls/month.

Except for one month in 2000 (18 days) and one month in 2003 (11 days) the well has produced 28 - 31 days of every month since it was spudded, suggesting that there has been no significant work-over since it was drilled. The months following those short months in 2000/2003 did not reveal any increase in production, again suggesting that no major work was done at that time.

I do not know for whom Empire Oil might be working, but as noted earlier, Whiting has shown a recent interest in this area.

For fuller coverage of the Tyler formation, see the sidebar at the right (other formations) or click here (same links). North Dakota separates these three formations (though they are very close to each other): Tyler, Tyler A, and the Heath.

A Re-Look at Merger and Acquisition Thoughts in the Bakken, North Dakota, USA

Sometimes while researching a question to answer for the blog, I am taken to areas where I did not expect to go. In other cases, I am taken back to articles that I read quickly some time ago, but now have the luxury to take some time and read them again, digesting very carefully what was being said.

That happened this morning, while researching a completely unrelated subject, when I returned to this Reuters article published October 11, 2010. This article had three major themes:

• The price differential between oil and natural gas is forcing oil and gas companies to shift attention to oil
• That focus is driving merger and acquisition plays in the tight unconventional shale fields
• The expense for developing tight unconventional plays will force mergers among the independents, in addition to acquisitions by the majors, of course

The mergers/acquisitions in the Bakken in 2010 (or earlier) come to mind:

• XOM/XTO
• Hess/TRZ and AEZ
• OXY USA/Anschutz (did Anschutz got completely out of oil, or did he redeploy to D-J)
• Denbury/Encore
• Fidelity/Oasis (not quite the same situation)

That is "old news" and reflects directly from the Reuters article linked above.

Re-reading that article, this jumped out at me (it is nothing new, it just hit me a bit harder than usual):

Looking ahead, however, smaller operators may need to seek external funding as service costs go up and maintaining multiple acreage becomes increasingly capital intensive.

"The higher costs will squeeze some of the smaller, less well capitalized players ... they may find that teaming up with larger players or selling out is a more viable option," said Robert W Baird's Murphy.

Private players such as Tracker Resource Development Inc, or small-cap listed operators Kodiak Oil & Gas Corp -- which had end-2009 proved reserves of 4.46 million barrels of oil equivalent -- and Oasis Petroleum would be the sort of firms that could be in this position, analysts said.

One analyst felt that we would see some additional merger/acquisition action before the end of 2010 (which did not happen) but:

Geoffrey King, energy analyst at Van Eck Associates, reckoned valuations of Bakken operators may not come down anytime soon, delaying M&A deals and joint ventures until well into next year (2011).

"It looks a stretch, but we'll maybe see some activity in 2011... I don't see a huge need for financing opportunities until then, unless commodity prices collapse," he said.

Commodity prices have not collapsed, but the scuttlebutt in the Williston Basin is that lease prices will increase 10-fold on those leases that expire at the end of this years. We might get a hint of what is to happen during the quarterly North Dakota state land lease sales.

North Dakota Land Lease Sales Results -- February 21, 2011 -- Some Tracts Still Fetch $9,000/Acre -- Bakken, North Dakota, USA

I did not see a news article on the quarterly North Dakota land lease sales results held February 21, 2011, suggesting that it was a smaller auction than usual.

Here are some of the highlights, by county:

Williams County: Several smaller tracts with bonuses of $4,500/acre

Mountrail County: Several smaller tracts with bonuses of $1,300/acre

McKenzie County:

• Much more activity, but still smaller tracts, mostly Diamond Resources
• Bonuses from $4,600 to $6,800
• There was one 80-acre tract acquired by Larco Resources for $7,600 (1-152-94); this is in Antelope field; relatively little activity in the immediate area to the north; CLR has one confidential well (Quale 1-1H in this same section (must be a great well); to the section to the west, CLR has another confidential well, Mack 3-2H; and in that same section (2-152-94), there are two producing wells: CLR's Mack 1-2H (IP 380, 83K in two years); and CLR's Mack 2-2H (IP 609, 47K in first four months)
• Clearly the better tracts in this sale

Stark County:

• This is the county where WLL has recent interest
• Many tracts sold; almost all acquired by Clear Creek Resources, LLC
• Almost all under $500/acre; a couple for $800/acre
• With one huge exception: Empire Oil paid $9,000/acre for five separate tracts (four 80-acre tracts; one 60-acre tract); sections 23/26-140-99 and section 1-139-99. These tracts are in the Zenith field, and there is absolutely nothing on the GIS map server from the current boom that would give any hint of the reason why these tracts sold for this amount. A Tyler-pool vertical well spudded in 1984 produced 120K over its lifetime; a Tyler-pool vertical spudded in 1981 produced 116K over its lifetime; and (this might be the reason), the Tyler-pool vertical well spudded in 1984 has produced 608,562 bbls to date and it is still producing at 2,000 bbls a month, and no decline for the past several years -- in fact, it has increased over the past few years.

Divide County: uneventful

Burke County: a few tracts for $1,300 (Petro-Hunt LLC)

Bowman: uneventful (four 160-acre tracts for $50/acre); Trinity Western

Dunn: only three tracts (80-acre, 2-acre, and 6-acre; $3,200 to $3,800/acre); Empire Oil

Slope: several tracts, but uneventful ($140 to $280/acre)

More On Waterflooding in the Alberta Bakken -- Implications for the Williston Basin Bakken?

From New Technology Magazine.com, June 7, 2010:

"We're going to continue to push the technology here. We're continuing to move more towards cement liners versus the Packer's system. We're moving more towards development of the waterflood then (sic) just focusing on primary drilling," [Scott] Saxberg said, adding that initial results indicate that waterflood has the potential to increase recovery factors in the Bakken from about 10 percent to 30 percent.

Scott Saxberg is the president and CEO of Crescent Point Energy Corp.

I do not understand the difference between cement liners and the Packer's system (although I have an idea what the difference is, but not confident enough to post it yet), and will provide more on that later.

For more on the Alberta Basin Bakken, start here (from the Edmonton Journal, December 9, 2010) and then here, my own take on the Albert Basin Bakken.