Drilling fever in the Rocky Mountains these days isn't entirely focused on natural gas. Along the eastern edge of the Rockies-in western North Dakota, eastern Montana and the southern parts of the Canadian provinces of Saskatchewan and Manitoba-more and more wells are being spudded throughout the 202,000-square-mile Williston Basin. The target: oil. The 143,000-square-mile U.S. portion of this huge sedimentary basin-whose hydrocarbon accumulations are largely attributable to structural traps produced by the folding and faulting of rock during the formation of the Rockies-isn't exactly unfamiliar hole-punching country to the industry. In the 1950s, the U.S. portion of the basin witnessed a boom in oil drilling as the result of the Beaver Lodge Field discovery by Amerada Oil Co. on the Nesson Anticline in North Dakota and the finds of the Richey and Southwest Richey fields by Shell Oil Co. in eastern Montana. By the early 1960s, further exploration of the Williston in Montana and North Dakota yielded the discovery of some 25 large fields, each with oil reserves greater than 15 million barrels. More than a decade later, the 1979-81 industry boom arrived and the Williston saw annual oil production in Montana hit a peak of around 32 million barrels in 1982, and in North Dakota a high of more than 50 million barrels in 1983. Then came $9 oil in 1986 and the economics of drilling up the Williston in Montana and North Dakota skidded. So, too, did oil-production levels. Companies pulled back their rigs. That, however, was a few yesterdays ago. Today, the Williston Basin-Oil and Gas Investor's first cover story (August 1981)-is undergoing a renaissance. "Although traditionally viewed as a mature oil province, the Williston is poised for oil and gas production growth from the Cedar Creek Anticline and the Mississippian-age Bakken Shale play, which is centered around Richland County, Montana, and nine counties in North Dakota," points out Andrew Strachan, Houston-based analyst for Wood Mackenzie, a U.K.-based global energy consulting firm. Why this renewed interest in the basin, particularly the Bakken? "The use of horizontal drilling and fracturing techniques has made the middle member of the 9,500- to 10,500-foot Bakken formation more accessible," explains Strachan. "Productivity gains [in this formation] have far exceeded the added expense of horizontal drilling in a rising cost environment. In addition, recent crude prices in excess of $70 per barrel provide a strong incentive to drill-given the typical break-even price range of $14 to $19 per barrel." Indeed, the ranks of Bakken players in the Williston are swelling. In addition to the presence of Enerplus Resources Fund, Continental Resources, EOG Resources, Headington Oil and American Oil & Gas, Marathon Oil recently announced the acquisition of about 200,000 Bakken leasehold acres in Billings, Divide, Dunn, McKenzie, Mountrail and Williams counties in North Dakota and Richland County, Montana. In these areas, Marathon plans to drill at least 300 wells during the next four to five years. Drawing upon its experience in horizontal drilling and well stimulation, the company believes the program has the potential to add more than 20,000 barrels of oil equivalent (BOE) by 2012, says Steven B. Hinchman, Marathon senior vice president, worldwide production, based in Houston. In addition, Houston-based Pogo Producing this spring announced the acquisition of about 46,000 net leasehold acres in North Dakota's Bakken where it expects to drill its first two horizontal wells in Dunn and Williams counties in fourth-quarter 2006. "This play is distinguished by very rich source rocks that encase fractured middle-member dolomite siltstones at depths of about 10,000 feet," says Pogo chief executive officer Paul G. Van Wagenen. "It's a developing play that has advanced recently through improved horizontal-drilling capabilities and modern completion technologies." According to the U.S. Geological Survey, the Bakken play in Montana and North Dakota has already produced billions of barrels of oil. Importantly, WoodMac notes that officials in those states estimate the total remaining oil in place in the Bakken may be as much as 200 billion barrels, some 20% of that recoverable. Separately, Denver-based St. Mary Land & Exploration Co. observes that overall proved oil reserves in the Williston Basin-from all play types-have recently risen to more than 750 million barrels, up from a 1994 level of 400 million barrels. Meanwhile, annual Williston oil production, which fell through much of the 1980s and 1990s, has rebounded to a 2005 level of around 68 million barrels-33 million of that in Montana; 35 million in North Dakota. The implication: the Bakken isn't the only play type drawing operators to the Williston. The prolific basin also boasts such oil-bearing strata as the Mississippian-age Madison Group play, which includes the Mission Canyon and Ratcliffe formations at average depths of more than 9,000 feet; the Duperow formation at around 11,000 feet; and the Red River formation at about 13,000 feet. Put simply, the oil-rich Williston is no one-trick pony, either geologically or geographically. And operators like Whiting Petroleum Corp., Bill Barrett Corp. and St. Mary Land & Exploration-through its Nance Petroleum subsidiary-are keenly aware of that fact. Multiple horizons Entering the North Dakota portion of the Williston Basin in 1995, Denver's Whiting Petroleum Corp. did so with the $20-million acquisition of some 10,000 acres of Bakken production. Today, however, it's focused on a wide range of prospects in that state situated on what has grown to 425,400 gross or 230,500 net acres of lease-holdings. These leaseholds include the Robinson Lake area in Mountrail County; the North Elkhorn Ranch, Magpie and the Big Stick Madison Unit in the Billings Nose area of Billings County; and the Nisku "A" play in the western part of Billings and Golden Valley counties. In these prospect areas, Whiting this year will spend an aggregate $65.3 million to drill 11 wells to the 9,500-foot Mission Canyon formation, 10 to the 10,100- to 10,900-foot Middle Bakken formation, nine to the 10,700-foot Nisku "A" horizon, one to the Duperow target, and six to the Red River formation, which is both oil- and gas-bearing. In addition, the company may drill four more wells to the Bakken in Richland County, Montana. The spending represents a 50% increase over the 2005 level. "We got into the Williston because of the attractive size of its reserves on a per-well basis; the as-yet large, undrilled prospects and repeatable opportunities within the basin, of which the Bakken is a good example; and the relatively moderate cost to acquire reserves in the ground-about $5 to $6 per BOE in 1995 versus double that today," says James J. Volker, Denver-based Whiting chairman, president and chief executive officer. "Also, the Williston is oily in nature, and we think we're in for a long-term period of strong oil prices." Volker notes that the Mission Canyon has per-well BOE-reserves potential of 140,000 to 150,000; the Bakken, 300,000 to 350,000; the Nisku "A," about 210,000; the Duperow, 130,000 to 150,000; and the Red River, upwards of 520,000. This year, in its major Robinson Lake area where it has assembled 110,000 gross or 82,000 net acres, the company plans single, dual and trilateral horizontal wells to the Bakken on 640- to 1,280-acre spacing. Drilling here isn't cheap. Completed costs on grass-roots horizontal wells in the Bakken can total around $3 million; in the Nisku "A," $3.6 million. The company, however, has found several ways to mitigate these high drilling costs. "In some cases, we've been able to do casing exits out of existing vertical wellbores before drilling horizontally-a step that can reduce well costs to about $1.5 million," says Volker. "In addition, after drilling the vertical part of these horizontal wells, we've been able in some instances to bring in large, powerful workover rigs rather than conventional rigs to drill the horizontal portions of the hole. "That can reduce dayrates from around $18,000 to between $11,000 and $12,000. Also, we use PDC (polycrystalline diamond cutter) drillbits, which allow us to drill faster and make fewer trips out of the hole and bit changes." Horizontal drilling, along with better fracing technologies, has made the Williston a bigger contributor to Whiting's overall reserves and production profile. Today, the Rockies represents 23% of its total reserves of 263 million BOE and 30% of its daily production of 40,900 BOE, says Volker. "Importantly, the Williston accounts for about 70% of our Rockies assets; comparatively, the basin in 1995 accounted for only 10% of our company-wide reserves and production." Although Whiting receives a $6 to $9 discount to Nymex prices for its 40Þ API Williston crude production-due to transportation issues, marketing costs and competition from Canadian heavy crude coming across the border-that's still a healthy realization amid $70-plus oil prices. What's also pretty healthy is the company's 95% drilling-success ratio in the Williston. Says Volker, "In general, what we're doing is field-extension drilling. So it's only a question of the variability of production on a per-well basis as opposed to not being able to find productive zones." Immature basin Through wholly owned subsidiary Nance Petroleum Corp., Denver-based St. Mary Land & Exploration Co.'s history in the Williston Basin effectively goes back to 1969. That's when Bob Nance, president of Nance Petroleum and now senior vice president of St. Mary, set up shop in Billings, Montana. "I recognized at the time that the Williston was one the biggest inland basins in the U.S., that it had very few operators, was hardly explored and had a lot of multi-pay potential-from the shallow Mississippian formations all the way down to the Ordovician-age Red River formation," says Nance. "When we formed a partnership with Nance Petroleum in 1991, the primary play for us was the Red River where we were able to achieve an 82% drilling-success rate with 3-D seismic mapping versus only a 15% success rate for others in the play," says Mark Hellerstein, St. Mary chairman, president and chief executive. During the balance of that decade and into 2003, St. Mary made several key acquisitions in the Williston, including the Choctaw properties in Richland and Roosevelt counties, Montana; Burlington Resources' properties in McKenzie and Billings counties, North Dakota; and Flying J's properties in Richland, Billings and Mackenzie counties. Also, in 1999, Nance Petroleum became a wholly owned St. Mary subsidiary. "These acquisitions gave us a tremendous position-865,000 gross acres; 455,000 net-in the relatively immature, multi-pay-zone Williston. We were virtually assured we would be a part of any major play that occurred there," Hellerstein says. "Three or four years ago, that play was the Bakken and we have acreage right in the heart of it." Development of the Middle Bakken through horizontal drilling in Richland and Billings counties is St. Mary's most active drilling program in the Williston. Between 2003 and 2005, it participated in 61 completed Bakken wells without a dry hole. The wells typically produce at initial daily rates of 300 to 600 barrels of oil, with reserves per well estimated at between 350,000 and 500,000 barrels. "We view the Bakken as a repeatable resource play, with 81 proved undeveloped, probable and possible well locations left to drill in the Williston," says Nance. "We're also getting into horizontal drilling in the Mission Canyon, Ratcliffe, Nisku and Duperow plays, while continuing our deeper Red River exploration program with vertical wells." That largely explains why St. Mary's capex budget this year for the Williston will be $89 million to drill and participate in about 70 wells versus spending $60 million last year to drill and participate in about 50 wells. Nance estimates that a typical grassroots horizontal well in the Williston will cost $3.2 million this year, up from $2.7 million in 2005. "However, we've learned more with every well we've drilled and, by using downhole motors and PDC bits, we've reduced by five days the time it takes to drill a horizontal. That translates into savings of around $100,000 per well." To further cut costs, the company is also using workover rigs to reenter existing vertical wells, then going horizontal with the same workovers rather than conventional rigs, says Hellerstein. "Using this approach, we wind up cutting our drilling costs more than half versus a grassroots horizontal." With the company's huge acreage position in the Williston, the immature basin's multiple-pay horizons and further 3-D seismic mapping of the Red River, St. Mary has been able to grow output and reserves despite the basin's 10% to 25% annual production-decline curves, he adds. Specifically, the company's net annual daily Williston production has grown from about 4 million BOE in 2003 to 4.76 million in 2005; net reserves, meanwhile, have climbed from 39.6 million BOE to 48.8 million. Lateral, vertical pays Shortly after Denver's Bill Barrett Corp. was started in 2002, it purchased Intoil Inc. whose Rockies assets included upwards of 20,000 acres of properties scattered throughout the Williston, with daily basin production of 400 barrels of oil and reserves totaling 20 billion cubic feet equivalent (Bcfe). "Being predominantly a Rockies gas producer, we felt it would be attractive to add a bit of diversity to our production stream by having a mix of oil in it," says Fred Barrett, chairman, president and chief executive. "Also, we saw tremendous upside potential in the Williston, which has established oil production from 11 major formations ranging in depth from 1,500 to more than 14,000 feet." In particular, the company is interested in the Madison, Bakken and Red River formations across seven project areas at depths ranging from 7,400 to 10,500 feet, explains Terry R. Barrett, senior vice president of exploration, northern division. "We drill wells vertically to these depths, then extend them horizontally up to 5,000 feet through the target zones." In many of the basin's formations there are multiple development targets in the same zone, providing the opportunity to expand laterally within the same horizon, notes Steven L. Reinert, senior exploration geologist. "At the same time, there are often other pays vertically up and down the hole that present additional development opportunities." The majority of the company's properties, both producing and prospective, are in a 50-mile radius of Williston, North Dakota, a major industry service center for the area. In this region, much of Bill Barrett Corp.'s recent activity has been focused on the Madison formation-a limestone and dolomite sequence that includes the Mission Canyon and Ratcliffe horizons-in its Target, Nameless, Indian Hills, Red Bank and Red Bank Extension areas. Last year, the producer participated in drilling 12 horizontal wells in the Williston as part of its overall $17-million spending program in the region. In its Madison drilling program, this effort translated into seven productive wells in the Target and Red Bank areas-with initial daily gross production rates of 47 to 238 barrels of oil-and the identification of 14 offset locations. Also, the company participated in three successful horizontal Bakken wells in its Mondak and Red Bank Extension areas in North Dakota. Results on a late 2005 Red River horizontal test were initially disappointing. "This year, we estimate our drilling and completion expenditures in the Williston will total $28.5 million, much of that aimed at drilling 14 horizontal wells," says Terry Barrett. This includes drilling five horizontal Madison development wells in the Target area, a second wildcat in the Indian Hills field, two additional horizontal Madison wildcats in the Red Bank Extension area, three Bakken horizontal development wells in Mondak and another horizontal Red River wildcat. Although typical horizontal-drilling costs per well in the Williston are high, the advantage of this drilling technique is that one horizontal well can drain a reservoir more economically and more efficiently than multiple vertical wells. Fred Barrett says, "In the Williston, we have an inventory of low-risk, multiple-pay development projects in front of us and an active exploration program, both of which will continue for years on our 126,800 net undeveloped acres there." Since entering the basin, the company has already demonstrated growth. At year-end 2005, daily production had risen to 7 million cubic feet equivalent; proved reserves, to 32 Bcfe. Bakken bent A Canadian royalty trust that went public in 1986 in a C$9-million IPO, Enerplus Resources Fund is today a C$7.5-billion market-cap entity with a total enterprise value of C$8 billion. Notably, it sees itself more as a typical E&P company, the key difference being that it is a tax-advantaged, pass-through entity that pays monthly distributions. Much the same as upstream MLPs in the U.S., it is an acquisition, development and growth-oriented investment vehicle-one that last year achieved 38% and 42% total returns for its Canadian and U.S. investors, respectively. This Calgary-based resource-play-focused company, involved in shallow-gas drilling in Alberta and Saskatchewan, coalbed-methane and oil-sands development in Alberta and waterfloods scattered throughout western Canada, entered the U.S. portion of the Williston Basin in August 2005 with its C$509-million purchase of Lyco Energy, a private Dallas producer, and a month later, the C$107.2-million acquisition of another private operator, Sleeping Giant LLC. (See "The Bakken is Back," Oil and Gas Investor, April 2004.) "Last year, we felt there was access to more and better upstream deals in the U.S. than in Canada," says Garry A. Tanner, Enerplus executive vice president and chief operating officer. "In particular, we were looking for concentrated assets with long-lived reserves, repeatable and attractive development opportunities, and a predictable decline curve." Lyco Energy and Sleeping Giant, with their focus on the 10,000-foot Bakken dolomite formation in the Sleeping Giant Field in Richland County, Montana, had all these attributes. In aggregate, Enerplus picked up a 70% working interest in 80 Sleeping Giant producing wells with daily output of 8,700 BOE, proved and probable reserves of 36 million BOE (based on the Canadian standard of reserve reporting), and 120,000 acres of undeveloped acreage in Montana and North Dakota. Wasting no time, Enerplus, during the balance of 2005, drilled 15 more successful horizontal Bakken wells at Sleeping Giant, exiting the year with daily production north of 10,000 BOE and proved-plus-probable reserves of 37 million. With a 2006 capex budget of C$89 million for the Williston, Enerplus plans to drill three wells per month in the basin, mainly targeting the Bakken at Sleeping Giant. Thus far, it has identified 55 remaining Bakken targets in that project area and is still in the process of testing the productive edges of the play, as well as the play's infill-drilling and secondary-recovery potential. Also, the company is exploring and evaluating similar Bakken play types in McKenzie, Williams and Dunn counties in North Dakota. "While the horizontal Bakken wells we're drilling at Sleeping Giant cost about US$3- to US$4 million to drill, complete and tie-in, they're nonetheless very profitable," Tanner says. "Initial peak oil-production rates on wells with 4,000- to 9,000-foot laterals have averaged 300 to 400 barrels per day-with ultimate reserve recoveries expected to range between 400,000 and 750,000 BOE per well." To make wells even more profitable, Enerplus has managed to reduce the time to drill its Bakken wells from 24 days to 18. In addition, it's re-entering many of those wells and refracing them to rejuvenate production and stem the typical sharp decline rates associated with Bakken wells. "Economically, the Bakken is an extremely attractive project-at US$60 to US$70 oil, we're looking at returns on investment per well of more than 200%." Still, what about the much-bemoaned price differentials to Nymex for Williston crude? Enerplus' production is being carried out of the Williston by Enbridge Pipeline, which has a number of access lines to various Midwest refineries. "So we're typically seeing only a US$4 to US$5 differential to Nymex for our 42Þ API Williston oil output," he explains. "In light of the economics of our Sleeping Giant project, we don't see that differential as a problem." This July, PrimeWest Energy, another Calgary-based royalty trust, announced its entrance into the Williston by a $300-million purchase of 47,000 net acres in Montana and North Dakota with current daily production of 3,200 BOE. It expects "a number of infill drilling and waterflood-optimization opportunities" in the Mississippian and deeper Devonian formations.