Another Lackluster Hess Well

Some months ago I was taken to task when I opined about the lackluster Hess wells based on IPs (yes, I know the argument).

Today, another Hess well was reported on the NDIC daily activity report: #18228, EN-Uran-154-93-1213H-1 (this link is now broken; suggestion that this dual lateral abandoned the Middle Bakken, and this is a fracked Three Forks Sanish well). Based on its designation, it's a long lateral. The IP was reported to be 225. This is about the same as other IPs for Hess wells in the same area; in fact the nearest Hess well to the EN-Uran had an IP of 225 (coincidentally) and another Hess well had an IP of 425. None of these are exciting. These wells are in the Robinson Lake field, just west of the prolific Sanish field. Adding insult to injury, this newest well (#18228) is exactly one mile west of the Sanish. Actually, none of the wells in the immediate area are all that exciting, on either side of the Robinson Lake/Sanish line. [Update, November 5, 2013: #18228 has now produced 136,560 bbls of oil.]

Perhaps more frustrating: this well was advertised as a dual lateral. If this is a dual lateral, it raises even more questions about the IP. Dual laterals target two formations: in this case, the two formations would be the Three Forks Sanish and the Middle Bakken. (See note above regarding abandonment of the Bakken lateral, and is now only a Three Forks Sanish well.)

Sinclair, yes, Sinclair, has a well 3.4 miles southwest of this newest Hess well (IP, 225) that reported an IP of 685. Not necessarily all that exciting, but better than 225 (by about three times).

We've been "spoiled" by four-digit IPs in the Bakken.

Update: even folks on the Bakken Shale Discussion Board asked about the poor performance (this link is now broken). At Bakken Shale, ChemGuy says "Bad frac.  Only a couple of stages were depolyed (sic) ...  Second lateral has not been frac'd yet." That may be, a bad frac, but all their wells in this area had similarly low IPs.

BUT, I am still waiting to see what the six Hess wells on one pad in Ross field do!

UPDATES

Update, October 22, 2010: It looks like I wasn't the only that has raised questions about the wells that Hess drills (this link is now broken).

Pipeline Capacity: For Those Keeping Track

A year ago, pipeline oil capacity in North Dakota was estimated to be 250,000 barrels/day. With the upgrades in the Enbridge system (+50,000 barrels) and the addition of the EOG Stanley railroad terminal (+60,000 barrels/unit train/day) at the end of 2009, the estimated capacity to ship oil was increased by 110,000 barrels/day, which would be 360,000 barrels/day.

With the announcement yesterday that an additional railroad terminal will be operational in the Dickinson area in October, 2010, estimated capacity to ship oil out of North Dakota should be 420,000 barrels/day.

Unlike pipelines, the railroad tankers are scalable. The tracks aren't scalable, but the number of unit trains are.

(Note: a few days from now the link above will be broken/lost due to the source. But I am sure you will be able to google another source for the story.)

(Note: as long as we're talking "pipeline capacity," here's an update on the TransCanada pipeline slated to go through Montana.  Although the pipeline is not currently routed to go through North Dakota, oil from that state could easily be shunted to Montana to join the TransCanada pipeline.)

Investing: QEP

As of November 14, 2010, this page will follow only QEP, not Questar. 

Yahoo!Finance: QEP

Finance!Yahoo: STR
4Q09 Earnings Conference Call
Annual Report, SEC Filing, 2009

NEWS

June 12, 2015: huge sand fracks.

January 30, 2014: QEP to spin of midstream business, QEP Field Services, will sell off non-core assets.

October 14, 2013: QEP will request permission to unitize the Helis-Grail. 

May 26, 2013: from Mike Filloon --

QEP Resources  has built a position in the Bakken to increase oil production. Some believe it spent too much to get the Helis acreage in northeast McKenzie County. My guess is it wasn't just purchasing the acreage, but also the know-how behind some of the best Three Forks wells in North Dakota. It closed the purchase in September of 2012. At the beginning of this, it began pad development. It has 4 rigs here, and plans a 5th by year end. It plans to stick with 8 wells per 1280 acre spacing. 4 wells will target the middle Bakken and 4 the upper Three Forks. QEP reported much lower crude production than expected in the first quarter. It spent the first three months of the year drilling pad wells in the Bakken. All of the wells must be drilled before completion work starts. This will push the majority of production into upcoming quarters. QEP only turned one South Antelope well to sales in the first quarter. The IP rate was not great at 1,397 boepd, but at the end of the first day of production this increased to 3,100 boepd. I don't like mentioning peak rates for production, but it is meaningful because the peak was at the end of the day and not the beginning. Well costs have decreased to $11 million in South Antelope.

QEP completed 11 Fort Berthold wells in the first quarter. Six (6) were middle Bakken and the other 5 in the upper Three Forks. The average IP rates were 2,190 boepd in this area. In Skunk Creek it completed 5 wells with an average IP rate of 2,479 boepd. A third party produced water gathering system is now completed, it saves QEP $5/barrel. Bakken crude sold for 96% the price of WTI or $90.81/bbl in the quarter. This compares to 88% the price of WTI in the first quarter of 2012. On the reservation, well costs are $10.8 million. It believes under $10 million as a target cost/well is possible by the end of this year. Decreased costs will be seen through pad drilling, fracs with more sand and using ceramic tails, but decreased drilling and completion times. Three rigs are running here. QEP has several pads under development. The most important is the Independence pad in Fort Berthold. It consists of 10 wells. One is being drilled with four waiting on completion. There are two additional four well pads on the reservation. In South Antelope, QEP has two four-well pads and one two-well pad. One of the four well pads has one drilling and three awaiting completion.

April 17, 2013: QEP has permits for 12 wells in one section in Heart Butte, in a 2560-acre spacing unit. 

November 1, 2012: highlights of 3Q12.

August 23, 2012: The Biggest Story of the Year to Date

• QEP Pays $1.3 Billion for Larger Stake in the Bakken
• Includes 27,600 net acres in the Heart of the Bakken 
• Black Hills Corporation sells some Bakken assets to QEP 
• Helis, LLC sells Bakken assets to QEP

April 9, 2012: QEP has completed drilling on its 10-well pad in Heart Butte oil field.

November 12, 2010: Questar approves spin-off.

July 15, 2010: Spin-off and name change, June, 2010. The exploration and development company, now known as QEP, was spun off from Questar Corp (STR) in June, 2010.

April 22, 2010: Questar is considering a tax-free spin-off of its exploration and production (E & P) businesses. One company would be involved with oil and gas exploration and production; the other company would be primarily a pipeline company.

BACKGROUND

I had not  heard of Questar (NYSE: STR) until I started following the Bakken. Questar might be something to consider by those who are concerned about the more speculative, smaller companies operating in the Bakken but don't want to invest in the major players in the Bakken either. Questar seems to be somewhere in the middle.

At first blush I would not have been interested in this company because it seems to be a natural gas play more than an oil play, and I don't know the natural gas industry as well as I think I understand the oil industry. (If I understand 1% of the oil industry, I understand 0.1% of the natural gas industry.)

I do not own any Questar shares and I don't plan to buy any in the near term. Here I look at Questar just as I looked at EOG some weeks ago. I also do not own any EOG shares.

COMMENTARY

A quick look at some basic data points from Yahoo!Financial key statistics regarding STR, compared to a few other companies operating in the Bakken, follows the commentary. The more I look at STR suggests this may be one of the few publicly traded companies that is very, very safe to invest in, and is just getting into the Bakken. This might be an opportunity to actually get into the Bakken if you have not yet invested in the Bakken. But Questar has major exposure to natural gas. Just saying.

Again, here is the link to the 4Q09 conference call.

The downside for me with regard to STR is their huge exposure to natural gas. The upside is the apparent interest by STR to increase their oil presence in the Bakken. The company has lowered its earnings estimates for natural gas going forward.

With regard to earnings, Questar had the second best earnings quarter (4Q09) in the company's history, only $200,000 lower "than the high water mark set in the fourth quarter of 2008." If folks remember correctly, we saw a price spike of $150/barrel of oil in 2008.

Questar is operating in five locations: Haynesville shale (Louisiana, natural gas); Pinedale Anticline Project Area (PAPA, Wyoming, natural gas), Granite Wash (Texas), Woodford Shale (Oklahoma, natural gas), and Bakken Oil.

In addition to these five E&P plays, Questar operates the following businesses:

Wexpro: E&P in the Rockies
Questar Gas Management: midstream business; could be a transforming year in 2010
Questar Pipeline: a regulated business; includes Wyoming
Questar Gas: a regulated business, natural gas distribution (Utah, SW WY)

Relatively high IPs were highlighted by Questar in their 4Q09 conference call, suggesting to me this company knows there is some value to high IPs. North Dakota passed tax incentives in 2007 to encourage drilling in the Bakken; the incentives affect the first 75,000 barrels of production.

Market caps; P/E; P/E, going forward; dividend (%); debt; operating cash flow:

EOG: $24 billion; 44; 15; 0.6%; $2.8 billion; $2.9 billion
STR: $7.5 billion; 19; 15; 1.2%; $2 billion; $1.6 billion
CLR: $6.8 billion; 96; 19; 0%; $0.5 billion; $0.375 billion
MDU: $3.9 billion; N/A; 12; 2.1%; $1.5 billion; $0.8 billion
BEXP: $1.68 billion; N/A; 24; 0%; $0.16 billion; $0.03 billion

Debt as percent (%) of market cap:

EOG: 12%
STR: 27%
CLR: 7%
MDU: 38%
BEXP: 10%

Is MDU an outlier with regard to debt as percent (%) of market cap?

MDU: $1.5/$3.9 = 38%
OTTR: 502 million 730 million = 69%
BKH: 1.15 billion / $1.12 billion = 103%

Is it possible to estimate Questar's potential recoverable oil in the Bakken?

Some data points: Questar has 80,000 net acres in the Bakken. (4Q09 conference call)
80,000 acres/640 acres per section = 125 sections.
In the best field (Parshall), EOG estimates 700,000 barrels EUR (per well)
EOG has been putting one well in each section
CLR opines that dual laterals could increase the EUR by another 400,000 barrels EUR.
36 sections/township: 125 sections / 36 = 3.5 townships.
At least one of "STR's townships" seems to be a "good" area.

Now some "back of the envelope calculations":
Let's say STR's acreage is 1/4 as good as EOG's best estimate: 1/4 of 700,000 = 175,000 bbls/well
125 sections: 125 wells x 175,000 bbls = 22 million barrels

What if they had 1/2 of the 700,000 plus 1/2 of what the dual lateral would add? 350,000 + 200,000 = 550,000.  125 wells x 550,000 = 70 million barrels. 

Activity in the Bakken

2008: three permits

17434, 880, 150-90, Deep Water Creek Bay
17929, permit, 150-90, Wild, nr DWCB
17940, 1,405, 150-90, Deep Water Creek Bay

2009: three permits

18158, 780, 149-90, DWCB
18322, permit, 150-92, Van Hook
18331, permit, 152-92, Van Hook

2010: four permits to date

18665, confidential, 149-91, Heart Butte
18666, confidential, 149-91, Heart Butte
18885, new permit, Deep Water Creek Bay, 150-90
18886, new permit, Deep Water Creek Bay, 150-90

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