After bursting onto the shale scene in early 2010, the Niobrara play quieted midway through 2011. Well results from horizontals drilled into this tight-oil formation in Colorado and Wyoming's Denver-Julesburg and other Rockies basins seemed to vanish overnight from analysts' reports and companies' earnings calls. Drilling slowed as operators assessed data from thousands of square miles of 3-D seismic shot in 2010 and 2011, over what has turned out to be a complex and challenging play. Leading operators brought technology to bear, while companies short on staying power sought a way out. Still others hunkered down while their more experienced, deeper-pocketed neighbors tweaked the drilling and completion formula.

On one point analysts, energy executives and bankers agree: The Niobrara isn't like other unconventional resource plays. It's more complicated. And just because your neighbor drilled a good well, doesn't mean you will.

Horizontal drilling to test the Niobrara shale in various Rockies basins has confirmed its reputation as a play of sweet spots. The D-J Basin remains the stronghold of the most consistent results to date.

A research note from Tudor, Pickering, Holt & Co. this past November assessed success to date over the various basins hosting Niobrara action. It termed Wattenberg horizontals "very economic/repeatable"; results outside of the field "spotty"; northern D-J Basin wells "uneconomic" to date; and thicker-pay Niobrara in the Green River Basin potentially "economic via verticals."

Indeed, some three years after EOG Resources Corp.'s Jake well raised hopes of another Bakken, the Niobrara has instead cemented its early reputation as a play of sweet spots. Jake cumm'd 50,000 barrels in its first three months and today is producing some 275 per day, and there have been other good—some very good—wells among the more than 250 horizontals drilled in Wattenberg Field and its environs. But attempts to establish this as a blanket resource play, with production solely from the matrix instead of in combination with natural fractures, have been stymied.

Venerable Wattenberg, now ranked 13th among U.S. fields in oil production and 10th in gas, remains the stronghold. Late in the fall, its dominant operators—Anadarko Petroleum Corp. and Noble Energy Corp.—rolled out vast drilling programs and annual capital budgets of more than $1 billion each to monetize Niobrara potential over the next five to 10 years. Embedded in their programs is, possibly, the next of Wattenberg's iterations: horizontal drilling in the Codell, a long-time vertical target.

Tight-oil complexities

What makes the Niobrara tougher than the rest? "After studying the Niobrara with all its variability and nuances, we've realized that the complexity of emerging tight-oil plays far surpasses tight gas—requiring more work to understand, in order to make better investment decisions," said the TPH research team in a midyear comprehensive look at the play's conundrums, operators, and potential.

The factors affecting production from tight-oil reservoirs include water saturation, relative permeability, reservoir pressure, and gas-to-oil ratios, the TPH research team noted.

In late January, a sign for one of Anadarko’s horizontal well locations in the Denver-Julesburg Basin is a brilliant marker against a backdrop of Colorado’s blue skies and the snow-capped Front Range.

Then there are what the team politely terms the Niobrara's "nuances." Its interbedded organic shale/marl/chalk intervals complicate drilling and completion. Its heavy faulting, in some regions, plays havoc with staying in zone. And its marls and shales' higher clay content can render hydraulic fracturing less effective.

In response, operators are using seismic and geosteering tools to stay in zone, and they are placing horizontals perpendicular to the principal horizontal stresses of the rock to improve and increase contact with fractures, the analysts said. Completion designs are also under study. Proppant flowback has been an issue, and wells often require artificial lift.

But while technical challenges linger, the Niobrara has compelling features beyond its liquids-rich bounty, not the least of which is infrastructure. Wattenberg is home to thousands of vertical wells, and for now, there is sufficient gathering, processing and pipeline capacity.

Further, all those verticals have armed companies like Anadarko and Noble Energy with plenty of data. Colorado's Oil and Gas Conservation Commission has established regulations that allow operators to proceed with clarity, for the most part. And, the exodus from dry-gas plays is prompting companies such as Chesapeake Energy Corp., active in the Powder River Basin Niobrara, to reallocate substantial capital to liquids-rich plays.

Operators’ plans call for an aggressive ramp up in Niobrara activity this year. Production is projected to rise fairly sharply in 2012 and beyond.

As 2012 dawned, operators were paring their lease positions and, in some cases, seeking joint-venture partners. Apache Corp. and Chesapeake have offered northern D-J Basin packages, and Newfield Exploration Co. is marketing its southern Powder River Basin acreage in Converse and Niobrara counties, Wyoming. In early January, Devon Energy Corp. announced a joint venture with Sinopec over its shale holdings, including Niobrara. Devon bought a large package of EOG's northern D-J Basin acreage, while Chesapeake also is selling a 200,000-acre package in the northern D-J. Carrizo Oil & Gas Inc., which has drilled about 10 horizontals northeast of Wattenberg, is seeking a partner.

Bill Barrett Corp., with some 65,000 net D-J Niobrara acres, this past August upped its position by acquiring D-J Basin assets from an affiliate of Texas American Resources Co., Austin, for $150 million. The acreage is in and near Wattenberg and Hereford fields (the latter is home to Jake).

And, companies are in the hunt to expand the play south. ConocoPhillips announced in late July 2011 it would acquire 46,000 net Niobrara acres from Lario Oil & Gas Co., Wichita, in Arapahoe, Adams, Elbert and Douglas counties, southeast of the Denver metro area and near the former Lowry bombing range. And at press time, the company had struck a tentative agreement with the Colorado State Land Board to lease oil and gas mineral rights under Lowry for $137 million, or about $6,500 per acre, plus a 20% royalty. If the deal closes, it will be the highest per-acre mineral lease price ever paid to the State Land Board.

Not to be outdone, Denver International Airport is considering bids for drilling on its land, northeast of Denver.

Ultra Petroleum Corp. last year leased more than 100,000 acres near Colorado Springs, in El Paso County, including an 18,000-acre ranch purchased out of bankruptcy. The company planned to test the acreage with four verticals early in 2012, but has met opposition. The Colorado Springs city council voted 8-0 on Nov. 30, 2011, to impose an "emergency ordinance" creating a six-month moratorium on applications for oil and gas operations within the city's borders, and El Paso County imposed a four-month moratorium on oil and gas applications in September. Ultra has filed permits to drill two wells on the ranch.

“What’s unique about the Niobrara opportunity is it is in the backyard of an existing field where we’ve had historic operations for over 30 years,” says Jim Kleckner, Anadarko vice president of operations, Rockies region.

Wattenberg roll-out

Wattenberg Niobrara development took a big step forward when Anadarko Petroleum in mid-November updated results from its horizontal Niobrara and Codell drilling program across 350,000 net acres. In 2011 it drilled 11 horizontal wells in the field. Based on its early results, the company said it was confident the liquids-rich horizontal Niobrara and Codell opportunity contained a net resource potential of 500 million to 1.5 billion barrels of oil equivalent (BOE) in Wattenberg.

The average initial production (IP) rate from its first 12 horizontal wells is 800 BOE per day. The company's Wattenberg economics are shored up by its extensive mineral rights ownership via the Land Grant position it obtained when it acquired Union Pacific Resources Corp. in 2000.

Anadarko estimates its future drilling locations in the field number 1,200 to 2,700, with estimated ultimate recoveries (EURs) of 300,000 to 600,000 barrels of oil equivalent (MBOE) per well. Well costs have averaged roughly $4.5 million, with a liquids ratio of about 70%. "Those costs result in an average internal rate of return of about 77% (assuming 65% crude, 5% natural gas liquids and 30% gas)," according to a report from Wells Fargo Securities.

"What's unique about the horizontal Niobrara opportunity is it is in the backyard of an existing field where we've had historic operations for over 30 years," says Jim Kleckner, Anadarko vice president of operations, Rockies region. "Our teams are established, and we've been investing over the past three years in science and technology to increase recovery using horizontal drilling and completion techniques.

"We've been investing in infrastructure—securing processing and gathering capacities, oil takeout and expansion opportunities. Today we have more than 50% of the area's gathering and processing, we have dedicated rigs, and we have our midstream partnership with Western Gas (an Anadarko-owned MLP that owns and operates select midstream assets).

"This gives us the ability to really manage how we invest in the field's development."

Oil take-away capacity will be tight from late-2012 until 2014, when the Pony Express pipeline begins service.

There is regulatory clarity as well, notes Kleckner. "The oil and gas commission has established field-wide rules that clarify investment regulations as to which portions of the field will be developed. They have streamlined the permitting process so it is transparent and navigable, while still being sufficiently robust."

As for the economics, Kleckner says the Wattenberg horizontal program would have been a prize even in the mid-1980s. "Because of our low investment prices and net revenue interest ownership, we can sustain low product prices for natural gas. Gas prices could be $2 or $3, and because the production is so liquids-rich and has such high oil yields, the field would be very, very strong.

"From an oil standpoint, it is such high-margin oil and liquids that it would have been economic at $18 oil. There are three very good product streams in the play, so it really broadens our market."

Anadarko is the largest acreage-holder and net producer in Wattenberg, at 76,000 BOE per day at year-end 2011. It operates more than 5,200 existing wells with an average working interest of some 96%. "Our subsurface teams have a complete understanding of Wattenberg because we operate so many vertical wells," says John Ford, general manager of the Wattenberg horizontal program. "We can target high-productivity areas right off the bat."

“We call it the magic of short-cycle oil in the U.S. onshore. It’s the best you can get,” says John Ford, general manager of Anadarko’s Wattenberg horizontal program.

As it rapidly scales up, Anadarko expects to drill 160 horizontals in 2012 vs. 35 last year, and 200 annually from 2013 forward. Just over a year ago, it had drilled its first Niobrara lateral. By the end of this year it will have at least seven horizontal rigs at work in Wattenberg as it accelerates development of the resource within a 10-year time frame. Its $1-billion 2012 spend more than triples its capital budget for the field in 2011.

As the horizontal program grows, the vertical program wanes—from five vertical rigs and three horizontals in 2011, to three verticals and seven horizontals this year. Cash-cow Wattenberg will eventually be largely self-funding. "In 2011 we will have had an EBITDA from this asset of more than $1 billion, and because we are so efficient, we have in excess of $400 mil- lion of free cash flow," notes Ford.

"We call it the magic of short-cycle oil in the U.S. onshore. It's the best you can get. If we could find 20 more Wattenbergs, we'd probably quit doing anything else."

How does the rate of return from Wattenberg compare with Anadarko's other projects in the U.S. and internationally? "From a portfolio standpoint, it is outstanding," says Kleckner.

Wattenberg horizontals average $4.5 million, with the best coming in at $3.8 million. In other onshore areas like the Marcellus or Bakken shale plays, wells cost $5- to $8- or $9 million, respectively. "We think the recoveries are as competitive as anywhere in the U.S. onshore," says Ford. "And when you layer in the additional net revenue interest from the Land Grant acreage, the economics are very attractive."

In 2011, Anadarko's 11 horizontal wells had an average payout of 10 months. The star in the group, the Dolph 27-1, paid out in less than four months. The Dolph's IP was more than 1,100 barrels of oil per day with 2.4 million cubic feet of gas for an estimated EUR of more than 600,000 BOE. "For an example of our midstream access, our best well, the Dolph, is within a mile of our main processing-plant infrastructure , and just a few miles away from our oil infrastructure," says Ford. Two horizontal rigs out of five are running in that area.

After its initial success within the field's boundaries, Anadarko decided to "check out the edges," says Ford. "We found that what we thought were the edges, weren't. We drilled wells with a 10-month payout on all the edges. Then we went to the far southeast of the field, where verticals haven't been economic, and drilled a horizontal that came in at 800 barrels per day. Everything we've done has been very robust.

Thomas F. (Toby) Darden, chairman and chief executive of Quicksilver Resources, says the company plans to drill at least five Niobrara horizontals in the Sand Wash Basin in 2012.

"This program is also low risk. There isn't any other play where we have such a good understanding of the subsurface because of the vertical development. We know where the good rock is, the good pressures, the good fluid—it's laid out right in front of us."

Says Carrie Horton, manager of reserves and planning, "Increased fracture-stage ability opened the door." To further optimize development, the company is looking at different well designs, spacing, using less proppant, and other factors. "It's still early in the game," she notes.

"We're looking to fine tune the process to maximize recoveries, but we leapt in with an understanding developed as a leader in the Eagle Ford and in the Marcellus, and as a historic operator in the Austin Chalk. We were able to transfer technology and get the recipe pretty close, pretty early."

The average number of stages currently is 20; the maximum to date is 30. The company uses Ottawa sand for fracs. Laterals are averaging 6,300 feet.

"In the main area of Wattenberg, we find a tremendous amount of open natural fractures, but that's not always the case," notes Ford. "Here, we are enhancing a system. One well had over 2,500 open natural fractures. This gives us a tremendous advantage over other plays.

"It all starts with the quality of the rock, fluids and pressure. We're seeing original virgin pressures in some cases, even with 15,000 industry wells having been drilled in the field."

Anadarko was able to transfer technology to Wattenberg horizontal operations from its work in the Eagle Ford and Marcellus shales to “get the recipe pretty close, pretty early,” says Carrie Horton, manager of reserves and planning.

Another reason the company likes Wattenberg: "It's the easiest drilling basin in the world," says Ford. Three of the rigs drilling the basin in the company's fleet drilled the most hole in the U.S. for 2011. Verticals average less than four days from spud to spud—a record was 51 hours—and horizontals require just 12 to 18 days to drill and complete.

Anadarko remains committed to a scientific approach as the ramp-up proceeds. "We want to do it right the first time," says Ford. It will continue to assess the reservoirs and optimum spacing, and it has a 260-square-mile 3-D shoot under way. It will prioritize its blocks through 2012 as well as do a "tremendous amount of microseismic," notes Ford. Also planned are full log suites, full fluid analysis and core lab analysis at its new lab in Greeley, Colorado.

"For the first time in Wattenberg's history, we can create full compositional simulation models the way we do internationally and in the deep water," says Ford.

The company is evaluating additional zones, and its two Codell horizontals have come on as strong as the Niobrara wells, with IP rates of 795 and 670 BOE. It currently has 18 horizontal Codell locations permitted in Wattenberg.

Helmerich & Payne Rig #308 drills the Camp 28N-25H targeting Niobrara shale in Wattenberg Field, Colorado.

Anadarko moved over the past two years to secure midstream and take-away capacity. It now has 385 million cubic feet of processing capacity in the basin and owns a 10% interest through Western Gas in the White Cliffs pipeline that moves crude to Cushing. The current capacity is 50,000 barrels per day, with expansion planned to some 120,000 barrels daily. It also has secured expanded NGLs take-away capacity with contract commitments on the planned Texas Express NGL pipeline to Mont Belvieu. And it has approved construction of a 300-million-cubic-feet-per-day cryogenic processing plant that can extract ethane at high recovery rates.

What target could daily production hit, and at what spacing? "We're still understanding our inventory and determining the most valuable spacing," says Ford.

This year, at any rate, production is expected to top 100,000 BOE per day. Noble Energy also produces nearly that daily number from the field. "So if you think about Noble, and us, and everyone else combined coming up—we're approaching 300,000 net per day from everyone. The Bakken just passed 450,000 and is headed to 1 million. We're on a ramp."

Outside of Wattenberg, Anadarko has amassed 550,000 acres. On its acreage in the Powder River Basin, it has two rigs drilling horizontally to test Niobrara, Frontier, Sussex and Shannon. One horizontal has been completed, but the results haven't been released.

"Not everywhere will be as strong economically as Wattenberg, and you have to drive costs down," says Ford. "That's what we're very good at. We've safely driven vertical well costs to $700,000. We have economies of scale, midstream capacity, and the Land Grant odd sections. If anyone can make it work, it's us. We're just getting started."

Noble's ninefold ramp

An equally powerful presence in Wattenberg is Noble Energy Inc., Houston. The company will spend $8 billion in the D-J Basin over the next five years, doubling overall production, increasing horizontal production ninefold, and doubling liquids production. By 2016, its liquids stream from the field will be about two-thirds of production. The company estimates its net risked resource in Wattenberg at more than 600 million barrels equivalent.

Inside the control room and, facing page, making a connection on a cold, blustery day in Weld County.

Noble Energy has some 400,000 net acres in Wattenberg operated with more than a 90% working interest. A leader in horizontal drilling, it has 58 producing horizontals in the Niobrara under its belt, and has tallied a 30-day IP average of 530 BOE per day, with an estimated average EUR of 310,000 BOE.

Its net horizontal production has more than tripled in the past six months, to a current daily figure of 14,000 BOE out of its 67,000 barrels of overall production from the field. Noble's most recent 18 horizontals reflect continual tweaks to drilling and completion, with average 30-day IPs of 600 BOE per day, and an average EUR of 350,000 BOE.

The company's average well costs are about $4.7 million, and its laterals average 4,500 feet with 19- to 20-stage frac stimulations. Spud-to-rig-release times have dropped by 30%, to about 13 days.

Ted Brown, senior vice president, Northern Region, notes that the company recorded a number of accomplishments and breakthroughs during the "quieter" period of the past 18 months. "These breakthroughs demonstrate how we are a leader in innovation and technology ," he says.

One of the most significant leaps forward was extending the economic limits of the field by 67%. Previously, a large portion of Wattenberg had been judged uneconomic or marginally economic for verticals. Horizontal drilling has expanded the economic areas—largely to the north and east—into what Noble Energy calls its "extension" area.

"Combined with the wells we've drilled over the past few months, we're now at a point where full-scale development can take place across our entire position within Wattenberg," says Brown.

This breakthrough germinated from 2007 to 2009, when the company began gathering hundreds of feet of core.

"We came to the realization after modeling efforts and better understanding the rock properties that vertical Niobrara wells in Wattenberg were draining less than 10 acres, and there was a tremendous resource in place. When you have 300 to 350 feet of hydrocarbon-bearing formation, you're just scratching the surface with vertical wells."

Noble Energy drilled its first horizontal in 2009, and in 2010 moved the play ahead another giant step with its Gemini well.

Pump truck operators monitor a frac’s progress in busy Wattenberg Field.

"A lot of people doubted that we could drill wells horizontally in the Niobrara in Wattenberg because it had been so heavily drilled vertically. We proved with wells like the Gemini that we can drill horizontals in the very heart of the field and essentially see virgin reservoir pressure and very economic wells."

The Gemini has cumm'd 250,000 barrels of oil equivalent. A later Gemini-type well, Tanner K33-65 HN, featuring a 5,400-foot lateral with a 21-stage completion between 10 existing verticals, also encountered original reservoir pressures. The average vertical, meanwhile, yields EURs of 40,000 BOE, including the Codell production.

The industry is watching Noble Energy's nine-well pilot program to test 80-acre spacing, again in its extension area. The pilot is also evaluating a centralized water and distribution system. 'We're looking at how we can move water around in the field via pipelines rather than trucks, and reduce our footprint with central distribution systems combined with recycling," notes Brown.

The pilot's EcoNode pad involves drilling wells from two pads on either side of a central production facility. It merges Noble's multiwell pad drilling experience in the Piceance Basin with innovations from Bakken shale operations.

Ted Brown, Noble Energy’s senior vice president, Northern Region, says the company’s breakthroughs over the past 18 months reflect its leadership in technology and innovation.

Having extended the field's economic limits, Noble is embarking on full-scale development, and the numbers are big. With close to 4,000 potential locations within Wattenberg, it plans to drill 250 wells annually, implying a 15- to 20-year inventory. A goal is to accelerate monetization of its horizontal Niobrara program to 10 years or less.

"You have to do a lot of forward planning and thinking," says Brown of the effort. "One of the things we've done is secure water—we have a very broad water-management system in place, involving procurement, transportation, storage, disposal and recycling."

Over the past several months, Noble has also secured frac crews, equipment and sand sup- plies and is working out other logistics so it can almost double its rig count, from five at yearend 2011 to nine by the end of 2012, focusing on the oilier extension area. In 2011 it drilled 75 horizontals, with eight to 10 completions per month; in 2012 it will more than double that amount to over 170 wells.

Of the 58 horizontals completed to date, 11 targeted the high gas-to-oil ratio area, with an average 30-day rate of 750 BOE per day and 40% to 50% liquids content; 22 were in the core area, with average 30-day rates of 550 BOE and 50% to 70% liquids; and 22 were in the extension area, with average 30-day rates of 480 BOE and 70% to 90% liquids.

Also closely watched is the company's extended lateral of 9,120 feet, Wells Ranch AE29-68 HN, completed in July 2011 in the extension area. The well improved finding and development costs by about 20%. Spud to rig release took just 17 days, with a 39-stage fracture stimulation.

"We'll drill 10 to 12 of those extended-reach laterals in the basin, at a cost of some $7.5 million each, in 2012," says Brown. By drilling an extended-reach lateral in place of two normal laterals, Noble Energy expects to save several million dollars and more than double recoveries, to some 600,000 BOE.

Noble Energy shot about 1,000 square miles of 3-D seismic in 2011 and owns or has access to more than 1,800 square miles. It intends to obtain 3-D over its entire lease position over the next three years. Just a couple of years ago, there was barely any seismic over Wattenberg.

"Wattenberg was never an area that was technology-driven," notes Brown. "Today, it's quite the opposite. We're using the latest 3-D interpretation technology, the latest completion techniques, and the most sophisticated stimulation fluids.

One of the most significant technical challenges has involved artificial lift design. "We have perfected gas-lift in this area to remove liquids from the wellbore," notes Brown. "There are areas that will require pumping units, but we have been focused on alternatives as we've extended and drilled out to liquids-prone areas for artificial-lift solutions."

Noble will continue to target multiple stacked-pay zones, including the Niobrara B and C chalks, the Codell sandstone, and possibly the Greenhorn chalks, as well as continuing an active vertical program.

Armed with proceeds from its recent IPO, Bonanza Creek Energy will drill some 24 horizontals and 92 verticals in Wattenberg this year, says president and chief executive Mike Starzer.

Outside Wattenberg, Noble Energy has about 460,000 acres across northern Colorado and southern Wyoming that it will further appraise and evaluate in 2012. It drilled 10 horizontals in the northern D-J last year with some encouraging results. But it will also watch and wait.

"One factor that has kept us from putting more rigs up there is limited infrastructure combined with no near-term expiring leases," notes Brown. "It is still an exploratory play.

"When you look at the recent results, the bottom line is we're averaging 45% to 50% rates of return in Wattenberg. We're focused on our oil-prone extension and core areas. And we can fund this with existing cash flow—Wattenberg generates its own program."

Refocus on Wattenberg

Denver-based PDC Energy, another longtime Wattenberg player, is also stepping up its horizontal Niobrara drilling program for 2012. It began drilling in early 2011 in the Wattenberg core area and results are positive. Currently, PDC estimates it has an inventory of 387 horizontal Niobrara locations on its 74,000-netacre leasehold in Wattenberg, or about three wells per spacing unit. CK Cooper estimates EURs at 310,000 BOE for a 30-month payout at $90 oil and $4.50 gas.

When James Trimble became chief executive of PDC in mid-2011, one of the first things he did was to refocus PDC's capital spending to liquids-rich Wattenberg and the high-impact Marcellus shale play. He has since sold the company's Permian Basin assets to focus operations and fund this year's capital program, and has stopped drilling in the dry-gas Piceance Basin.

"Last year we drilled 17 horizontal wells, 80 vertical wells and did 180 refrac/recompletes in Wattenberg," says Trimble. "This year we plan to increase activity to 27 horizontal wells and 210 refrac/recompletes. We have a 14-year horizontal drilling program and a five-year refrac/recomplete program at that rate." About 85% of its $198-million development capital budget for 2012, or $168 million, will be spent in Wattenberg. The company will not drill any verticals this year.

A tool lies at the ready on a drilling site in Weld County, Colorado.

"The horizontal Niobrara and refrac/recomplete programs both have a great rate of return," says Trimble. "The refracs are in the Codell, which was the main zone companies drilled several years ago. We have found that the wells have a hyperbolic decline, and after six or seven years, production flattens out. If you refrac them, they increase to 70% to 80% of the original production rate and repeat the same decline. We also recomplete them in the Niobrara and then commingle the two zones."

Trimble notes that this past summer, a lot of companies jumped into the Niobrara play in various areas of Colorado and Wyoming outside the core of Wattenberg. Some reported mediocre wells, prompting some investors to assume the Niobrara wasn't all that good.

"PDC got lumped in with all the guys drilling along the Wyoming border," he says. "But we have 74,000 net acres in the Niobrara, it's all held-by-production, and nearly all the acreage is in the core area of Wattenberg where the industry is reporting some of the best and most consistent Niobrara results. We are the third-largest producer in the core, and the production is about 80% oil and NGLs."

PDC has succeeded in growing its oilier as- sets, propelled by Wattenberg, to 66% gas, 22% crude oil, and 12% NGLs today, versus at yearend 2010, 79% gas, 15% crude, and 6% NGLs. Its proved reserves in Wattenberg have increased by 51% to 459 billion cubic feet equivalent, from 303 billion cubic feet equivalent in 2010.

Newly public

Niobrara potential this year helped to launch newly public company Bonanza Creek Energy Inc. (NYSE: BCEI). Late in 2011, the longtime Wattenberg-focused private company, cofounded by Mike Starzer, Gary Grove and Patrick Graham, sold 10 million shares at $17 each for a total raise of $170 million. The company's portfolio also includes holdings in southwest Arkansas' Cotton Valley oil trend and legacy assets in California.

In 2001, Starzer, who had worked for Berry Petroleum as vice president of corporate development, joined Bonanza Creek as president and chief executive to lead it through a period of growth in Wattenberg. "As we grew, we delivered a great return to our owners," he says. "We went to the institutional capital arena and raised $50 million from D. E. Shaw in 2006, followed by another $50 million in the following two years."

The company purchased Cotton Valley trend assets in 2008 from Macquarie Oil & Gas Holdings Inc. And in late 2010 an investor group led by Toronto-based West Face Capital Inc., together with company management and the D. E. Shaw group, completed an equity financing of $265 million, monetizing the predecessor company, Bonanza Creek Energy Co. LLC, and financing some $150 million in senior and subordinated debt.

From the beginning, Bonanza assembled a team with expertise in operations and engineering, including Grove, a petroleum engineer who is chief operating officer; Graham, who has extensive fracing and stimulation experience from his years with Dowell-Schlumberger; and Jim Casperson, who joined in 2011 as chief financial officer, a position he held previously at Whiting Petroleum Corp., which he took public in 2003.

"We're also strong on the geoscience side, which is important as we continue to grow by the drill bit and acquisitions as a public company," notes Starzer.

In November 2005 the company sold five of its largely gas-producing Wattenberg properties and became 70% oily, well ahead of today's rush to liquids-rich plays. It now holds 63,000 net Niobrara acres—roughly half in Wattenberg, and half in Colorado's North Park Basin.

It has drilled hundreds of verticals in Wattenberg and is well acquainted with the field's geology and drilling methods. Last year it drilled about 60 verticals and four Niobrara horizontals there. Its overall production is some 6,105 BOE per day as of November, with Wattenberg contributing about 2,706 of the total, 70% liquids. The company's acreage is northeast of the field's historical core.

Armed with IPO proceeds, and minimal debt, Bonanza Creek will drill about 24 horizontals and 92 verticals in Wattenberg through the first two-thirds of 2012 with four rigs it has secured. Its horizontals to date have posted average 24-hour IPs of 788 BOE per day and 30-day rates of 458. Its laterals are averaging 4,000 feet with 16 stages.

"Once we moved forward on the latter three horizontals, we averaged more than 50 barrels per day per stage on the IPs per well," notes Starzer. The horizontals cost $4.2 million, which Starzer expects to trim to $4 million.

Bonanza has a $146-million budget for Niobrara and Codell drilling in 2012. The company targets production growth of 120% year-over-year.

Says Casperson of the Niobrara, "Some people call it a resource play; others call it an old oilfield with a new way to develop it. It's somewhere in between."

North Park's potential also has the company excited. "When we screened the Rockies for potential Niobrara plays, one of the parameters we had was vertical production that looked good, and North Park has that. Niobrara verticals there have produced between 40,000 and 100,000 barrels, and the formation has the same attractive thermal maturity as Wattenberg," says Starzer.

The company has been building its acreage position there since 2006. This year it will take horizontal three verticals drilled on its 30,000-acre position in 2010. It has 2-D coverage of the area but is shooting 3-D. The first lateral should kick off in third-quarter 2012.