Extension areas with extended-reach wells. Multiple targets offering a variety of well configurations to maximize recovery. Well performance that seemingly improves with increased density. Compelling economics in an area where infrastructure is nearby or not too distant. What’s not to like about the ever-expanding horizontal Niobrara play in Colorado’s Wattenberg Field and greater Denver-Julesburg Basin?

In reality, the play is not just about the Niobrara, although the most common targets to date have been its A, B and C benches, along with an emerging horizontal Codell play. And while Wattenberg Field has been home to many innovations in practices and technology, the Niobrara’s thrust today extends well beyond the field’s boundaries, to the north and northeast and, recently, to points south.

Ted Brown, Noble Energy Inc. senior vice president, describes his company’s key role in Niobrara development as “a methodical road to success,” but notes that by second-half 2012, “we had witnessed a complete transformation.” By the third quarter the company’s vertical program was at an end and horizontal well production had taken off, reaching 42,000 barrels of oil equivalent per day (BOE/d) by the end of 2012 from a total of 280 horizontal wells.

What is so striking, relative to just 12 or 18 months earlier, is the degree to which the ramp has not only taken hold but accelerated among the main players. The two largest Niobrara producers—Anadarko Petroleum Corp. and Noble Energy—are each budgeted to drill 300 horizontal wells here in 2013. For Anadarko, this is roughly double its horizontal Wattenberg activity. For Noble, the jump to 300 wells compares to some 200 in 2012. However, if adjusted for as many as 60 wells that are planned to have extended laterals (versus standard, 4,000-foot laterals), the programs are equivalent to drilling some 350 wells.

Caution in the early transition to horizontal drilling has given way to a substantially greater confidence in the play’s potential. Noble Energy has nearly doubled its inventory of risked horizontal locations, which now stands at 9,500. Likewise, Anadarko counts 4,000 drill-sites in its inventory, up from 2,000, and says the new number may prove “somewhat conservative.” And PDC Energy Inc., the No. 3 Niobrara player, says it has 2,000 locations, based on proved, probable and possible (3P) reserve estimates.

Drilling programs also have come into focus, even as trials continue to refine the optimal configuration of target zones and well density. Based on the geology of a region, for example, is it best to lay out a series of tightly spaced Niobrara B bench wells? Or a pattern of alternating Niobrara B and C bench wells? Or maybe a combination of Niobrara A, Niobrara B and Codell wells? Some configurations contemplate as many as 30 wells per section.

Several Niobrara players still have tests under way and have not finalized their drilling programs. However, after disclosing that the Codell likely underlies 98% of its acreage, PDC Energy’s 2013 budget allocates 50% of its drilling capital to Codell wells, 40% to Niobrara B wells and 10% to Niobrara C wells. Another Niobrara player, Whiting Petroleum Corp., is pairing up Niobrara A bench wells alongside its B wells in its Redtail region northeast of Wattenberg.

But if participants are now seeing more distinctly the main character lines of the Niobrara play—and with enough clarity to select favored zones and to discuss downspacing options—how was the face of the Niobrara so blurred previously that complaints were heard of the play being “patchy” and its drilling results inconsistent?

In the wake of the prolific Jake well, drilled by EOG Resources Inc. in 2009, hopes were raised for another Bakken-style liquids play. A land grab ensued, as new entrants tested acreage north of Wattenberg in search of a blanket resource play. Dry holes and a lack of immediate take-away led to the departure of many participants. This left continued development of the Niobrara largely back in the hands of its existing stakeholders, notably Noble Energy and Anadarko.

Data driven

As early as 2007, Noble Energy began studying why its Wattenberg vertical wells were draining less than 10 acres, or just 1% to 2% of original oil in place, recounts Brown. In the wake of the Jake well, Noble Energy’s early analysis led it to drill the horizontal Gemini well, which averaged 500 BOE/d during its first 60 days online in the summer of 2010. Despite the risk of depletion from 18 vertical wells in the same section, recalls Brown, “there was no depletion and no interference. And that was the biggest well ever drilled in Wattenberg Field at that time.”

This sparked an aggressive program of gathering additional core and petrophysical data as well as data on well completions, fracturing fluids and flowback. Companies shot 3-D seismic and collected downhole data. “We started to pick the play apart,” says Brown, noting information was also gleaned from the company’s 8,000 existing vertical wells in the play. Activity picked up further in 2011, with Noble’s nine-well pilot to test 80-acre and 40-acre downspacing at its Wells Ranch location.

“We collected more data there than the Hubble telescope,” Brown says. “The whole play for us has been data driven.”

For Noble Energy and other Niobrara players, the data collection and application of new horizontal drilling techniques have quickly proved game-changing. Says Brown: “The play is growing exponentially and has a tremendous amount of running room, not only for Noble Energy and the companies in the play, but also for the state of Colorado.”

Noble Energy estimates the industry’s oil production in the play is likely to double over the next two years.

The company soon recognized that an entire 300-foot section—comprising the Niobrara A, B and C, plus the deeper Codell formation—was “productive and capable of delivering some very strong economics,” Brown says. Estimates of original oil in place (OOIP) for the Niobrara subsequently tripled. Late last year, the company’s risked recoverable resource estimate swelled 60% to 2.1 billion barrels, buoyed by a near doubling of its drillsite inventory to some 9,500 horizontal locations. In addition, the company’s estimated ultimate recovery (EUR) of its standard lateral Wattenberg wells moved to 335,000 BOE from 310,000 previously. Noble Energy has budgeted nearly $10 billion in capex for the Niobrara for 2013 to 2017.

Moving north

Of Noble Energy’s 640,000 net acres in the Niobrara play, some 410,000 lie in the Greater Wattenberg Area (GWA), with the other 230,000 net acres in its Northern Colorado extension area. The GWA acreage is largely de- lineated and is split between an oil window (290,000 net acres) and a natural gas window (120,000 net acres). The GWA oil window accounts for roughly two-thirds of each of the remaining horizontal drilling locations and risked resources (6,400 locations and 1,400 million barrels, respectively).

While plans are still in the “early stages,” the company’s base case foresees developing the GWA oil window on 40-acre spacing in most areas. “When you look at the nine-well pilot that we drilled, we were very encouraged when the results from the wells that were spaced closest together—essentially 40-acre testing—performed the best. The closer you drill the wells, the better they perform,” observes Brown. “When we lay out our development plans, our teams are counting on 16 wells in a section.”

Operators have predominantly drilled Niobrara B bench wells to date, but Brown says tests are ongoing and some mix of target intervals is to be expected. “We’re not finished with that yet,” he says. “It’s just 16 wells right now. Some of those may be in the A, and some in the B, or C, or Codell.”

Although the company’s base case provides for 16 wells per section, one development pattern under study would allow for 30-plus wells, comprising Niobrara A and B bench as well as Codell targets.

Of the 230,000 net acres in northern Colorado—previously its “extension” area—Brown considers 45,000 net acres located in the East Pony area to be de-risked so far, “with some pretty phenomenal results up there.”

At 85% oil, the liquids content in northern Colorado is higher than the 65% in the GWA oil window, and EURs are also a touch higher, at 345,000 versus 335,000 BOE (both assuming standard laterals). Plans call for 80 wells to be drilled in the region this year. Gas-processing capacity is being added in the region, currently served by the Lilli plant, with a second plant, the Keota Gas Plant, sanctioned earlier in 2013.

As in Wattenberg, Noble Energy conducted a three-well pilot in northern Colorado to test 80-acre density, with 24-hour initial production (IP) rates coming in at 840 BOE/d and 30-day rates averaging 720 BOE/d. “The 80-acre wells are performing well,” says Brown. “We haven’t done a 40-acre test up in northern Colorado yet. But we have no reason to believe we won’t have a similar case up there as well, with the closest spaced wells performing the best.”

The company’s inventory of 9,500 horizontal drillsites includes 1,750 in northern Colorado, where less dense, 89-acre spacing is currently assumed.

Another area of potential growth for Noble Energy is its increasing use of extended-reach laterals.

“What’s been encouraging for us with the extended-reach laterals is the fact that not only do we have very strong economics, but you’re seeing a different decline curve, a much flatter decline curve. And when your finding and development (F&D) costs are 15% to 20% lower than with a 4,000-foot lateral, all of a sudden it becomes very attractive to start drilling more of these,” Brown says. “We’re trying to understand just how big the potential is for extended-reach laterals.”

Noble Energy has budgeted for 60 extended lateral wells this year, with all but five in the GWA oil window. The laterals typically measure up to 9,000 feet—with some now approaching 10,000—versus a standard length of 4,000 feet. Average drill and completion costs for an extended-reach well run $8.3 million versus $4.5 million for a standard lateral in the GWA oil window, while its EUR is estimated at 750,000 versus 335,000 BOE for its GWA counterpart. This offers potential F&D cost savings of 17% ($13.83 per barrel versus $16.79 per barrel, assuming 80% net revenue interest, according to the company).

Extended-reach laterals are not assumed to be entirely risk-free in terms of execution. However, similar to the way program economics helped reduce spud-to-rig-release times for standard lateral wells—now down to just six days for some—a program of 60 extended-reach wells should further accelerate the learning curve and help improve performance. Already, the shortest spud-to-rig release for an extended-reach well has come down to just over 10 days.

Beyond 2013, with a 300-well program, including 60 extended-reach wells, how does the ramp look? “The breakthrough goal is 500 wells by 2015,” says Brown.

Low-cost winner

As with Noble Energy, Anadarko has plenty of domestic and international plays competing for drilling dollars. But Wattenberg Field rises to the top of the U.S. list for “reserve replacement efficiency,” a metric it uses to compare, by basin, EBITDAX generated by a barrel of production with its finding and development cost per barrel.

“I believe Wattenberg is today, and will be tomorrow, the lowest-cost horizontal resource play in the U.S.,” says Jim Kleckner, vice president of the Rockies region for Anadarko. “The drilling is benign. It’s a very straightforward formation to drill and complete in, so we can drive down our drilling and completion costs. And because it is in an area with substantial infrastructure and development, our connection costs are low. We can drill a typical 5,000-foot lateral horizontal well, with 25 to 28 stages, through the tanks, for around $4 million, and generate rates of return that exceed 100%.”

Two factors give Anadarko an advantage in the Niobrara. First, when the company acquired Union Pacific Resources in 2000, it acquired a massive mineral position in the form of the Land Grant, which enhances the company’s returns as it collects the royalties. This greatly expanded an initial Wattenberg position that it inherited with its Kerr-McGee acquisition in 2006. Second, when Anadarko acquired gas processor Western Gas Resources, again in 2006, it also gained what it dubs a “midstream value uplift” for its upstream Rockies production.

The upstream acquisitions have resulted in Anadarko now holding a leasehold and mineral position in the D-J Basin totaling more than 900,000 acres, including some 350,000 acres in the core of Wattenberg.

To illustrate its “mineral ownership advantage” that applies to wells drilled on the land grant, Anadarko compares the before-tax, net present value (NPV) for wells subject to normal industry economics with those drilled on the land grant. It calculates a $5.3-million NPV for the former, but indicates the NPV rises to $7.7 million when adjusted for its royalty position in the mineral acreage as well as a reduced capital burden.

These economics assume an EUR of 350,000 BOE, a well cost of $4.3 million, and unescalated Nymex prices of $90 per barrel for crude and $3.50 per thousand cubic feet (Mcf) for natural gas.

Based on a risked net resource estimate of 1- to 1.5 billion barrels, and assumptions similar to those outlined above (including a $6.7-million before tax NPV per well), Anadarko projects a “line of sight” to $15 billion of value, up from $12 billion less than a year ago. Beyond 300 wells in 2013, the goal is to reach more than 500 wells “in the next few years.”

The path to that goal, however, is shaped more by the Niobrara geology and infrastructure buildout than by simply adhering to a lin- ear timeline.

“Our position is we are going to go about this judiciously, as we understand the different sections of the reservoir system as well as the impact of rock properties and natural fracturing in the field on our total resource size, and on the well count necessary to develop the resource,” says Kleckner.

Midstream assets and other infrastructure needed over the next five to 10 years are being planned so that bottlenecks do not occur and turn upstream investments into “fallow or stranded capital.”

Like others, Anadarko has yet to finalize an optimum combination of target zones and possible spacing requirements. “We’re currently testing multiple development configurations. Our philosophy is that we don’t want to have to go back for anything,” says Kleckner. “We want to run all the field tests necessary to characterize the reservoir system and determine the optimal well spacing.”

Kleckner describes the Niobrara formation as a transitional reservoir system moving from a gas condensate in the center to black oil on the periphery. “We see different spacing optimization based on where you are on that transitional reservoir system,” he says. One scenario involves a combination of roughly 12 Niobrara and six Codell wells per section, with greater density of Niobrara wells in black-oil areas and less in condensate areas. “But that example is just an average of what we see across the field,” he notes.

Anadarko has drilled 12 extended-reach lateral wells to date, with some showing “really outstanding results,” he says. “We’ve seen some of the wells with very low decline rates.”

For 2013, plans call for 40 to 50 more wells, with base-case economics viewed as more favorable than drilling two standard lateral wells. “All things being equal, it’s a lower-cost solution if we can reduce the mechanical risks of longer lateral completions.” In addition, the extended-reach laterals offer “a unique solution for Wattenberg, because it helps to reduce the overall footprint,” Kleckner says.

Even with the Niobrara already in a positive free-cash-flow position, Anadarko is happy to bring in partners to accelerate the play’s development, given a close to 15-year inventory of 70% to 100% rate-of-return projects it can drill in Wattenberg, Kleckner says. Last year Anadarko sold 59,000 acres prospective for Niobrara and Codell south of its core Wattenberg Field position to ConocoPhillips for $114 million, retaining a 20% royalty and a drilling commitment on its fee acreage.

Building a position

PDC Energy Inc., Denver, credits having “a couple of lead blockers” in Anadarko and Noble Energy for some of the early upfield progress. But PDC seized an opportunity to build a much more meaningful position in the play with its $330.6-million acquisition of Wat- tenberg assets from a private E&P, Merit Energy Co., Dallas, in May of 2012. It increased its acreage by almost 50% to approximately 100,000 net acres.

The acquired assets were valued largely on the existing vertical wells, plus an assumed horizontal well count reflecting a single Niobrara zone, the B bench, being developed with four wells per section. Since then, however, “the horizontal Codell has blossomed for us,” says Jim Trimble, PDC chief executive officer.

Well-spacing assumptions have moved up “three- or fourfold” to 12 to 16 wells per section. By year-end 2012, this translated into an inventory of 1,400 Niobrara and Codell locations to drill, based on 2P reserves, up from 546 locations post-acquisition.

PDC thinks the Codell is present and prospective under 98% of its acreage using horizontal drilling. This outlook began with a well drilled in a northern area where “vertical economics were subpar,” recalls Bart Brookman, senior vice president, exploration and production. “It ended up being one of our best-performing wells, and we quickly realized that the Codell provided another layer of opportunity for us in a whole different zone.”

Data on permeability and oil contribution helped select the location in the face of disappointing vertical well results. “Was it a little risky? Sure,” Brookman says.

With 300,000 and 500,000 BOE bands to its type curves, PDC appears to edge towards a separate type curve for Codell wells. Decline rates for over 70 wells—predominantly Niobrara B bench wells—point to an average EUR of about 340,000 BOE currently. However, Codell wells—albeit still only a handful—track more closely to the upper band of 500,000 BOE.

“We have some confidence that the Codell could perform better,” says Brookman, with the caveat that development closer to the core of Wattenberg over the long term would encounter areas where the Codell has been extensively refraced.

PDC indicates the bulk of its drilling this year will involve 12 wells per section, but will also include some tests on 16 and 18 wells per section. The primary focus will be Codell, Niobrara B bench and Niobrara C formations (split roughly 50%, 40%, and 10%, respectively), with the A bench being a later target—one the company is “not giving up on,” Brookman notes. Most of its wells will have 4,000 to 5,000-foot laterals, determined mainly by the layout of its acreage.

“The potential reserve growth in the Codell is going to be tremendous,” Brookman says, “because we are very underbooked in the Codell relative to our capital program.”

At its recent analyst day, PDC said its downspacing tests in the Niobrara B bench pointed to 40-acre density being necessary for optimum recovery. This raises the visibility of its inventory to 2,000 drillsites from a 2P estimate of 1,400 locations, based on eight Niobrara wells and two Codell wells per section. At an upcoming test on its 16-well Waste Management pad, PDC plans a configuration of six Niobrara B bench wells, four Niobrara C wells and six Codell wells. It also disclosed that its single Niobrara C well to date has been tracking closely to a 500,000-BOE type curve, similar to early tests in the Codell.

A widening scope

Since drilling its first four horizontal wells to the Niobrara B bench in 2011, Bonanza Creek Energy Inc. has widened its scope of development, with 56 Niobrara B wells with standard 4,000-foot laterals budgeted for this year, as well as trial wells. Results have come through from last year’s trials involving the company’s first C bench and Codell wells, plus an extended-reach lateral in the B bench. Trials this year are expanding to four wells in each of the C bench and Codell, plus two more extended-reach laterals in the B bench and a six-well, 40-acre downspacing pilot, also in the B bench.

The C bench well, which was among the first results released by industry, had a 30-day IP rate of 444 BOE/d. The extended-reach lateral (9,000 feet) had a 30-day IP of 795 BOE/d, in spite of being unable to complete the last 1,000 feet of lateral, and came in at a favorable cost of $7.4 million. The first Codell test, at a 30-day IP of 370 BOE/d—and a 60-day rate only marginally lower at 367 BOE daily—tends to support the Codell having a shallower decline curve and possibly higher type curve and EUR. All three tests showed over 75% crude oil.

Mike Starzer, chief executive officer of Bonanza Creek, is confident that all of its 31,700 net acres in Wattenberg have been derisked for 80-acre development in the Niobrara B. The C bench is also thought to be present on all Wattenberg acreage, while the Codell is viewed as productive on about 15,000 net acres, since it thins as it moves east. The A bench is considered prospective across the entire acreage, too, but this is not being emphasized, pending results from Noble Energy’s tests nearby on the Niobrara A.

Gary Grove, Bonanza Creek executive vice president, engineering and planning, provides a perspective on developing the larger Niobrara/Codell complex. “While we talk about this being economic at 80 acres in the B bench, we believe the ultimate opportunity is to place laterals in multiple benches to maximize the connectivity between the reservoir and the wellbore across the entire 300-foot section of the Niobrara/Codell complex,” he says. “We hope to make meaningful progress in determining the right spacing and lateral configuration in 2013.”

While Bonanza Creek’s April analyst day was expected to include an update of its drilling inventory to reflect downspacing options, the analyst community has already moved in that direction, pointing to over 700 net locations if both B and C benches are developed on 80-acre spacing and Codell on 160-acre spacing. A Credit Suisse report points to over 1,000 net locations if infill development moves to 40-acre spacing.

Last summer Bill Barrett Corp., based in Denver, acquired just under 43,000 net acres in what it calls its Northeast Wattenberg area. The acquisition builds on its prior positions in the Wattenberg interior and Chalk Bluffs and brings its total acreage prospective for Niobrara development to about 75,000 acres. A smaller, western part of its recent acquisition lies a few miles south of Noble Energy’s Wells Ranch area, while the larger part is east and southeast of Wells Ranch and in proximity to some Bonanza Creek acreage.

Scott Woodall, Bill Barrett’s interim chief executive officer, makes clear that accelerating activity is a top priority for the new area. Two-thirds of a $200-million budget will be for pad drilling in the western portion. The other third is earmarked for delineating the larger eastern acreage, where “most of the acreage will have a test on it by the end of the year.” In the west, results from 12 wells drilled on three pads have averaged 30-day IPs of 412 BOE per day. In all, plans call for 65 gross (45 net) wells this year.

Encouraging of late have been three wells drilled in the western acreage that have all had 30-day IPs ranging from 410 to 440 BOE/d. Two wells are within roughly two miles of Noble Energy’s successful extended-reach lateral tests and within three miles of its 40-acre density test wells. Even with the caveat that vertical well control in the area is minimal, Woodall expresses confidence that “the acreage is quality acreage, and it’s going to work.”

An extended-reach lateral may be considered later in the year, but for now the focus is on the basics: de-risking the acreage and drilling standard Niobrara B wells.

Bill Barrett is projecting 1,082 gross (509 net) locations on its Wattenberg acreage, which is based on 80-acre and 160-acre spacing in the core northeast Wattenberg area. With the Noble Energy 40-acre downspacing test within two miles, “if they’re claiming 40-acre spacing, and we’re on 160-acre spacing, obviously we have room to move,” observes Woodall. He notes it is early in the game, but the potential “is huge for us as a company.”

Further northeast, adjacent to Noble Energy’s East Pony area, Whiting Petroleum Corp. is set to go into development mode early this summer with a pad rig being added to start “tight space development” on 80-acre spacing, says Mark Williams, senior vice president, exploration and development. The company has just under 80,000 net acres in its Redtail Niobrara area, “and we think at least 80% of our acreage is going to be significantly productive.” The Niobrara B is viewed as the primary target, with the A bench considered “a strong contender” for development on a selective basis.

What does Whiting see in the A bench? “We haven’t proven it everywhere yet, but we have two areas where the A zone looks like it is going to be very good,” Williams says. “The A zone is actually richer in some areas than the B; it depends on where you are in the basin. It just isn’t quite as thick.”

A possible development would be eight B bench wells per section, with four A bench wells staggered above the B. “But the reality is that if four is going to work, you might as well drill eight A wells per spacing unit, because you’re only getting out a couple hundred feet on your frac jobs.”

With the lower permeability in the Niobrara, Williams observes “there are two things you have to do: you have to drill in tight density or close spacing, and you have to frac it pretty hard.” Overall well costs are expected to range from $4- to $5.5 million, depending on lateral length, as benefits of pad drilling are offset by completions using bigger frac sizes—4.5 million pounds, up from 2 million.

EURs are expected to range from 320,000 to 390,000 BOE, as lateral length varies from 4,800 to 7,500 feet. A new gas-processing plant is planned to come on by early next year, allowing a third rig to be added.

Whiting projects an inventory of roughly 1,200 net horizontal locations, based on eight Niobrara B wells and four A wells per spacing unit, using a combination of 640-acre and 960-acre spacing units. How strong are the economics? With the recent Wildhorse 02-0214H well flowing at an IP of 660 BOE/d, “we think we have an economic play just the way it is, and we think we can make it even more economic,” says Williams.

“It’s a technology question. If we know there is oil in place, we will figure out how to get it out. And there is more oil in place in this play than there is in the Bakken,” he says.

A unique path

If Whiting is closer to the perimeter of the Niobrara play, Synergy Resources Corp. is nearest its heart. The company, headquartered on Highway 60 in Platteville, Colorado, has gained attention from analysts for its leverage to a play dominated by its bigger brethren. The company is also about to spud its first operated horizontal well, after many months of participating on a nonoperated basis with other players—Noble Energy, PDC and Bill Barrett—and after many years of operating its own vertical/directional program.

Synergy has charted a unique path, consolidating acreage in the 2008-2009 financial crisis, monetizing $8.6 million of noncore acreage in the Niobrara land grab and reinvesting it in Wattenberg, and building a leasehold that combines municipal land alongside more typical E&P acreage surrounding the greater Greeley, Colorado, area. Of late, the company has achieved 20% sequential quarterly production growth from a base of vertical wells producing predominantly from the Codell.

The spudding of its first operated horizontal well, expected in May, marks another chapter for Synergy. In its fiscal year ending August 31, 2013, the company expects to operate four or more horizontal wells, as well as participate in nine nonoperated horizontal wells. In the following 12 to 15 months, it anticipates participating in another two dozen wells for which it has received authority for expenditure (AFE). Synergy plans to keep 75% to 100% working interests in its operated wells in Wattenberg.

“This is the most exciting time I’ve seen in my 30 years of watching the evolution of what’s taking place in Wattenberg. And it just keeps getting better,” says Ed Holloway, chief executive officer. In terms of “stepping up to the plate” as operator of a horizontal program, “you want the shortest payout period possible. And it’s clear the economics are pretty compelling now, particularly for the Niobrara B bench and the Codell,” he says.

Synergy has 16,355 net acres in Wattenberg Field as well as 19,400 net acres in the northern D-J Basin. Holloway estimates the entire Wattenberg acreage is prospective for the Niobrara and the Codell, although approximately 5,000 acres of the Codell have been previously developed with vertical wells.

Initial plans call for drilling up to five Niobrara B wells and three Codell wells on a 320-acre spacing unit. Longer term, a development pattern of 16 to 25 net wells per 640-acre unit would translate into an inventory of 325 to 550 net horizontal locations, comprised of stacked wells in three Niobrara benches and the Codell.

One of Synergy’s distinguishing features is the acreage it holds in surrounding municipalities, an area it exploited earlier with directionally drilled wells and soon will with horizontal wells. Synergy’s wells, for example, produce from under Greeley Country Club. “Municipal drilling has become our niche, and we feel we do a great job,” says vice president of operations Craig Rasmusson. “That’s virgin rock that hasn’t been tapped.”

Synergy also stands out for its plans to test the Greenhorn formation. Under a joint venture with private E&P Vecta Oil & Gas Ltd., a horizontal well to test the Greenhorn limestone that underlies the Niobrara will be drilled by October 31, 2013, at a location south of Noble Energy’s East Pony area. Based on data from a 1955 well, the location has “some of the thickest Greenhorn in the D-J,” says Holloway.

And how far afield is the Niobrara prospective relative to its core?

Far to the north, there are reports of SM Energy having had a successful horizontal well in the Powder River Basin in Converse County, Wyoming, with the 1-36H Moonlight-State flowing at an initial rate of 335 barrels of oil and 464 thousand cubic feet of gas per day. And far to the south in Colorado, Shell Oil is reported to have found a “working hydrocarbon system” based on cores taken from a horizontal well—the first of four it has permitted—drilled in Huerfano County. Studies of the core, taken from the Freeman 3-24, may take a year or more to complete, according to the Huerfano Journal.

Niobrara players, in many cases, have more than a decade of drilling given their abundant inventory of drillsites. The question then becomes, how do they accelerate drilling to bring forward the NPV of wells?

“Obviously, you have to expand the infrastructure, and drill the wells that maximize that expanded infrastructure in a very synchronized fashion,” Anadarko’s Kleckner says. In addition to having capable rigs, a trained and knowledgeable workforce, and plans already in place for an expanded infrastructure, what else makes a recipe for success?

“A very large and significant land base that is enhanced by mineral interest ownership,” comes the quick response from Kleckner. “Everything we have throughout our acreage position is either held by production or held in perpetuity. This gives us tremendous flexibility that enables us to optimize returns and accelerate the value of the play.”

Most operators don’t enjoy the same mineral ownership that Anadarko has. But it appears they all have significant Niobrara and Codell running room, and the numbers keep getting better.