Whiting Petroleum’s ‘sweet spot’ is most prolific part of the Bakken

The Smith 11-7H framing the Kannianen 11-5H in ND Bakken.Photo courtesy of Jim Blecha, Jim Blecha Photography Inc.

OIL & GAS FINANCIAL JOURNAL: What is the potential for the Bakken?

MARKWILLIAMS: If the entire Bakken formation were fully developed using today’s horizontal drilling and completion technologies, the USGS in April 2008 estimated that about 3 billion to 4.3 billion barrels of oil could be extracted with an average of 3.65 billion barrels. If you compare the Bakken to all the other oil plays in North America, excluding Alaska, the Bakken ranks as the No. 1 play in the country.

OGFJ: What are some of the geologic characteristics of the Bakken?

WILLIAMS: The Bakken formation is located in North Dakota and Montana inside the Williston basin. Generally, it gets shallower the farther east you go. It produces from depths ranging from roughly 8,000 feet down to about 11,000 feet. There are really two different plays there. The Bakken was produced early on along with two large fields along the southwestern margin of the basin, one in Montana and the other in North Dakota. Both of those fields are on the west side of the basin. With today’s new technology, the play has changed a little bit and it revolves around the maturation of the Bakken Shale – that’s where all the oil comes from. The shale part of the Bakken is extremely rich in organic carbons – the upper part and the lower part. The thermal maturation of that shale liberates oil, which is then trapped in place, and that is the focus of most of the drilling activity today on the eastern side of the basin.

JIM VOLKER: The Bakken can be divided into the Upper Bakken, the Lower Bakken, and the Middle Bakken. Within the Middle Bakken, there’s the zone that we actually drill horizontally through. That particular zone is what we call the “B Zone.” It has the best reservoir characteristics of any one of those portions of the Bakken. It has the highest energy and is the coarsest-grained unit in the Middle Bakken.

OGFJ: What specific fields are you referring to?

WILLIAMS: Whiting is currently drilling in the Sanish and Parshall fields located in the eastern Bakken in North Dakota. The reservoir continues across a broad portion of the state, but the Sanish and Parshall fields are what we call the “sweet spot,” the area within this very large field where production is greatest. This is the most prolific part of the Bakken.

VOLKER: Mark, maybe you could talk about the distribution of recoveries in the Bakken.

WILLIAMS: We have a chart that shows all the wells drilled in North Dakota since 2000, and they’re all rated from best to worst by initial daily oil rates – that is, how much oil is produced from the very first day of production. About 85% of the wells drilled had initial rates of less than 1,000 barrels of oil per day. The other 15% had initial rates of more than 1,000 barrels per day. Most of these 15% are in the Sanish and Parshall area.

OGFJ: How did Whiting first get into the Bakken?

JIM BROWN: Whiting was a participant in about five wells in the Elm Coulee field that were drilled in the early part of 2000 and shortly thereafter. We weren’t the operator. At that time, we tasked our technical folks to find another part of the basin where we could find a similar situation as in the Elm Coulee. They identified an area in the eastern part of the Williston basin [the Sanish field] where there had not been a lot of drilling activity and which they thought had great potential in the Bakken. So we started our own leasing program, and we leased up about 118,000 acres in this area. Our land costs were under $100 per acre, which is how we got from Elm Coulee to where we are now.

We also had an opportunity to lease the Parshall field, but we didn’t act on that right away, so EOG Resources picked up that acreage and drilled their discovery wells and got us very excited. So we drilled a couple of wells over on the Sanish side, and then we were able to come back in and pick up about a 20% working interest on the Parshall side of the field. So we have non-operated interest in Parshall, and we operate the Sanish field, where our working interest is about 82%.

OGFJ: Who are you partnering with in the Sanish?

VOLKER: We have a participation agreement with a privately-held independent oil company. As Jim said, we have a large acreage position in that area. Whiting owns interest in 93 units in the Sanish field. Of the associated wells to be drilled in 2009, we’ve taken 26 of those units and done a participation agreement. Under the agreement, the private company has agreed to pay 65% of Whiting’s net working interest completed well cost to receive 50% of our working interest and net revenue interest in the first and second wells planned for each of the units. The agreement will allow us to continue to increase production while prudently managing our capital resources by repaying debt. As a result of the agreement, Whiting’s finding cost of all producing wells drilled under the agreement will improve by 30%.

OGFJ: What are your drilling results to date?

RICK ROSS: The highest production rates are right after completion. Our Richardson Federal 11-9H was completed at 4,570 BOEs per day. That’s the highest rate Bakken well completed in the state of North Dakota. To date, we have eight wells that produce at over 3,000 BOEs per day, so 25% of our wells are over 3,000 and 56% are over 2,000. We only have two wells under 1,000 BOE per day, so 94% are over 1,000. So this is really very strong production compared to wells in other oil plays across the US. In the first 30 days, we’re averaging more than 900 barrels per day, and the first 60 days over 800 barrels per day. In the North Dakota Bakken play, we’re head and shoulders above everybody else.

OGFJ: What type of EURs (Estimated Ultimate Recoveries) are you seeing?

BRENT MILLER: We have a typical decline curve for the Bakken wells in North Dakota. All these wells have produced for less than two years, so when we go out 15 years, we are extrapolating quite a bit. So there’s some uncertainty about exactly where our EURs will be, but we think there is a very high chance it will be in the neighborhood of 600 to 700 MBOEs from each well. We definitely have EUR reserves in the Sanish field that range between 600,000 to over a million barrels equivalent in this field. Our east side wells are performing very, very well, and I personally think we’re going to see the high side of these EURs in Sanish field.

JIM VOLKER: Don, I’d like to point out that it’s not just Whiting that has provided these ratings, it’s our independent engineers as well – Cawley Gillespie & Associates.

OGFJ: What is your average completed well cost, and is it economical with today’s oil prices? Have your drilling costs declined in the current environment?

VOLKER: Our costs have some relation to oil prices in that we’ve seen some moderation in costs as the price of oil has declined. There are fewer rigs working and fewer pumping services – crews like Halliburton and Schlumberger who do the fracing of our wells for us. So as there has been less demand for their services, they have adjusted their prices downward somewhat. When we first started drilling in the Bakken, our prices were as high as $8 million to $10 million per well. Today they’re down to about $5.5 million per well.

OGFJ: How else have you reduced drilling costs?

MILLER: We’re becoming more and more efficient at drilling our wells. In 2008 we averaged 41 to 44 days per well. This year we have a record well that took just 29 days from spud to completion. We’ve seen a dramatic reduction in drilling costs. On the completion side, our costs last year were fairly high. Contractors were booked up, and they didn’t have to be very competitive. That has changed dramatically this year, and we’re working our costs down significantly. We have some long-term contracts that we’re trying to work through and get those costs down as well.

OGFJ: Moving on to economics, what is the break-even point with regard to oil prices?

VOLKER: Let’s assume a NYMEX price of, say, $45 a barrel. At this price the differential between NYMEX and the field would be about $5. So that means at the wellhead, we’d be receiving about $40. About 20% of that $40 goes to the landowner from whom we’ve taken our oil leases. About 20% goes to operating expenses and production taxes. Therefore, we have about 60% of that $40, or about $24 a barrel. Let’s take a typical EUR. If our range of reserves is about 800,000 BOEs per well, that’s about $19.2 million in revenue per well. If our well costs are $5.5 million, it’s roughly 3.5 to 1 on your money.

OGFJ: Those are pretty good economics.

VOLKER: Yes, pretty good economics even with lower oil prices. Our part of the Bakken is easily economic down to $45, and it even works at $35 a barrel.

BROWN: The way we calculated the economics, we ran two scenarios. The first is the proved-case reserves of 700,000 BOE per well and the second is the proved plus probable, which got us up to one million. We expect our production to be somewhere in this range, so we ran this at various oil prices. So at $60 oil, we’re looking at an IRR of basically 16% to something over 100% – maybe 110%, somewhere in there. And an ROI of somewhere above 3 and less than 5.

VOLKER: The ROI figures are the multiples of our investment that we get back. If the ROI is 4 to 1, then for a $5 million well cost, we’re looking at $20 million of future revenue.

BROWN: These economics were all run with a $6 million well cost. We ran these a while back, and we were a little conservative on our well costs. Very attractive return PV(10%) metrics.

VOLKER: PV-10 is the number reflective of how much present value at 10% we add to the value of the company from each well that we drill, assuming that we own 100% of the well. So the PV-10 value at, let’s say $60, would range somewhere between $6 million and $12 million based on the 700,000 to one million BOEs. The present value calculation starts with a negative, which is your well cost, which in this case we use $6 million, and then present value factors are applied to the future net revenues that come simply applying these prices to the decline curves that we showed you before – net of royalties, operating expenses, and production taxes. And so that stream of future net income then is discounted back to present value after it’s offset the original negative, which is the investment. The net result is how much PV-10 value we add to the value of Whiting each time we drill a well.

OGFJ: With that in mind, what are your future development plans in the Bakken?

VOLKER: We’ve drilled 61 wells to date, and there are another 105 potential locations there. And those numbers do not include Three Forks, the zone that immediately underlies the Bakken.

OGFJ: How much of Whiting’s total production comes from the Bakken?

BROWN: If you look at our first quarter production from 2009, we were at 54,320 BOE per day. The Bakken currently represents about 28% of our total production, so the Bakken is a very important piece of Whiting. And we expect that percentage to edge up as we go through the year.

OGFJ: How much of your 2009 CAPEX budget is allocated to the Bakken and how much have you used so far?

VOLKER: The Bakken represents 44% of our drilling budget, or $175.2 million out of $398.3 million. At this time, our drilling program is designed essentially to match our discretionary cash flow [about $400 million]. This is roughly a 40% cutback from our $970 million budget last year when our cash flow was greater. Still, we expect to grow production this year by 5% to 10% while staying within our discretionary cash flow and therefore not increasing our debt. If prices rise and our discretionary cash flow increases, we would become more aggressive.

OGFJ: Thank you all very much for your time.