Rocky Mountain Operators Fix Their Sights On Tight Oil And Shale Plays

Transcription

1 JULY 2012 The Better Business Publication Serving the Exploration / Drilling / Production Industry Rocky Mountain Operators Fix Their Sights On Tight Oil And Shale Plays By Kari Johnson Special Correspondent Activity levels and initial production rates in unconventional plays continue to astound operators as well as industry investors. Things are rockin in the Rockies! The Bakken Shale, of course, is at the top of the list. The Bakken has led the charge into the U.S. tight oil frontier, and production from the Bakken formation in North Dakota has skyrocketed from less than 100,000 barrels a day three and a half years ago to 550,000 bbl/d, according to the state s Department of Mineral Resources. To the south and west, horizontal drilling and multistage fracturing techniques also are opening the expansive Niobrara formation at depths to 14,000 feet, where companies are ramping up activity that is spreading across the Denver-Julesburg Basin and well outside the Wattenberg core area. In Montana, headlines about activity in the emerging Heath Shale the uppermost formation overlying the Madison Group in Central Montana have the industry s attention. Meanwhile, independent operators report that other oily formations such as the deeper Mowry Shale at 8,000-9,000 feet in Wyoming are yielding positive early drilling results and demonstrating the potential of a new round of tight oil plays. Reproduced for PDC Energy with permission from The American Oil & Gas Reporter

2 Extended Reach Begins The D-J Basin is one of five core areas for Houston-based Noble Energy. Its primary activity is focused in the liquids-rich Niobrara play in the Wattenberg Field, but Ted Brown, senior vice president of Noble s northern region, says the company is expanding drilling into the northern and eastern reaches of Colorado. Our plan is to spend about $1.5 billion this year in Colorado, which is more than one-third of the company s total 2012 capital program, Brown reports. We expect to drill more than 180 horizontal wells this year and invest in infrastructure. Over the next five years, we have plans to invest $8 billion in the Niobrara. With 880,000 acres to develop, Noble has plenty of running room and is positioned to achieve double-digit production growth over the next five years, according to Brown. We started recompleting Niobrara vertical wells in In 2007, we determined that verticals were draining only about 10 acres, he states. In 2009, we drilled our first horizontal well, followed in early 2010 by the Gemini horizontal well. That well was drilled in the more permeable, high-gas-to-oil ratio portion of the Wattenberg Field, offsetting a number of existing vertical wells, and was completed with 16 frac stages. It turned out to be the best well drilled to date in the Wattenberg, with an estimated ultimate recovery of more than 700,000 barrels of oil equivalent. Thus far, Noble has drilled five extended reach wells, each with laterals extending 9,000 feet or more. We are drilling down 7,000 feet and then horizontally about 9,000 more, so you can imagine that increases the mechanical risk, observes Brown. The early results are very promising. He says stimulating the extended-reach wells is very similar to a standard lateral, which uses cross-linked gel fluids with stages. The extended reach has stages in the same configuration. Wattenberg is relatively hot, compared with other basins, and cross-linked gelled fluids work very well here, Brown comments. The company has derisked its 410,000-acre position and is in the development phase within the Wattenberg Field. Its land position lends itself to long laterals, Brown remarks, adding that Noble also is encouraged by results from its 230,000-acre position north and east of the Wattenberg Field. He says Noble energy also has 240,000 acres in southern Wyoming waiting to be explored. Noble Energy expects to spend $1.5 billion this year more than one-third of its 2012 capital program investing in infrastructure and drilling more than 180 horizontal wells in Colorado. Over the next five years, the company has plans to invest $8 billion developing the Niobrara Shale. Focus On Recovery Noble Energy is gearing for more activity, Brown continues. The company has seven rigs drilling horizontally in the Wattenberg and will have two more in the fourth quarter. The company also is operating three rigs in its vertical program, ramping down to two by year-end. Brown says the company continues to drill vertically where there are additional horizons such as the J-Sand, expiring leases, or acreage that is isolated in a way that is not conducive to a lateral. We really are focused on recovery, both from the lateral and vertical wells, he says, adding that Noble Energy is looking at how many laterals can be put in a section and how best to drain the stacked, 300-footthick hydrocarbon saturated interval. We have 80- and 40-acre pilot tests, with nine wells drilled in a section in the low gas-to-oil ratio area of the play. Those wells have been on since mid first quarter 2012, Brown reports. Microseismic plays a large role in monitoring and improving drilling practices, Brown mentions. We really have leveraged that to understand the potential lateral as well as vertical drainage patterns, he says. We monitor closely while we stimulate to learn what we can do better next time. The company also is performing refracs and recompletions to enhance recovery from older wells. We generally see percent of the original production following the refrac, Brown details, adding the company operates 7,700 wells in the DJ Basin. It s all about how to get remove oil and natural gas from this tight rock in the most efficient and environmentally responsible manner. It is obvious that even after all the work we have done, we are not draining very large areas with those verticals, he says. That is why the refracs and triple fracs have worked so well. Expanding The Play The majority of Noble Energy s wells have been drilled in the Niobrara s B bench, but Brown says a dozen test wells are in the C bench. The company also has completed a test in the Codell and plans to drill six-eight more tests this year. He says the test was in the high-gor part of the core Wattenberg Field. There were about 30 wells drilled in that section already with a fair amount of vertical drainage. We intentionally placed the well where it had the greatest potential for drainage, figuring that if it worked

3 saw there was a partnering opportunity to provide cleaner air, save fuel costs for the district, and replace old busses in the fleet, he recounts. Brown cites these investments as examples of Noble Energy s long-term commitment to the DJ Basin. With its stacked formations containing hydrocarbons, there are likely to be more resources here than we thought initially, he concludes. Applying new technology really is starting to look like a step change for Wattenberg. there, it would work elsewhere, Brown details. We really have only scratched the surface here. We continue to be encouraged as we drill wells and conduct a tremendous amount of science. Early this year, the company acquired about 48,000 acres in northern Colorado. We have seen some very promising results there, Brown allows. We plan to extend what we have learned in the Wattenberg Field into the north and east. The company will be drilling wells as it delineates its new holdings in northern Colorado. We should have a pretty good feel for where we want to drill by the end of the year. Right now, this area is a combination of exploration and development, Brown reflects. He says the production in northern Colorado is more than 85 percent liquid. There is not much well control, so that is where you really leverage the seismic, Brown imparts, pointing out that the company has 1,000 square miles of 3-D shot across the play, and drills both exploratory and development wells based on the data. It s been extremely helpful in unlocking a lot of the acreage in northern Colorado, allowing us to push the limits of the Wattenberg Field, he acknowledges. Noble Energy is adding infrastructure in northern Colorado. Brown says the company has committed to building a 12- inch, 37-mile oil pipeline that will connect to its White Cliffs delivery point near The majority of Noble Energy s Niobrara wells have been drilled in the formation s B bench, although it has drilled a dozen test wells in the C bench. The company also has completed a test in the Codell and plans to drill six-eight more tests this year. The Codell test was in the highgas-to-oil-ratio part of the core Wattenberg Field. Platteville, Co. The company also has expanded its operations in Greeley, Co. This spring, it dedicated $15 million in new facilities at an event attended by the Colorado governor, mayor of Greeley, and other local officials. As part of the dedication, Brown says Noble launched a new social responsibility effort that committed to converting Weld County School District busses to run on compressed natural gas. We Going After The Heath Central Montana Resources has made a heavy bet on the Heath formation, which President and Chief Executive Officer Kevin Beiter says has been referred to in some circles as similar to the Bakken. The company was formed in 2007 and has its principal offices in San Antonio, and land and operations offices in Billings, Lewistown and Miles City, Mt., covering both ends of the play. Although these are still early days, Beiter says there is great optimism that the years CMR spent in data collecting and field delineation will pay off. Industry projections are for 10 million-17 million barrels per section. We focused on the Heath as a continuous resource based on some pretty strong indications that it had been a very effective source rock for 130 million plus The Heath Shale spans 120 miles east to west and 40 miles north to south in Central Montana. Considered by some to be a continuous resource play similar to the Bakken Shale, it is projected to contain 10 million-17 million barrels of oil equivalent per section.

4 barrels of production in the area, Beiter says, noting that early studies showed very high total organic content and favorable lithology. Since 2007, CMR has been accumulating and perfecting its land position to 514,000 net acres. The area, which spans about 120 miles east to west and 40 miles north to south, had not been extensively explored, Beiter says. There were only limited geologic data from logs and some anecdotal information from historical publications. He says CMR s first wells were drilled in 2010 to gather data. Over the past year, the company has drilled four horizontal and 10 vertical wells over a 70-mile span, gaining greater information about the geology and continuity. It now has sufficient coverage of about twothirds of the center part of the play to being developing an understanding of the area s geology and functioning petroleum system, Beiter asserts. Gathering Data CMR s first two horizontal wells Shadowfax and Snowmane were drilled in the western portion of its leasehold, west of the Musselshell River in Petroleum County, Mt. Beiter says Shadowfax was drilled and completed to 6,425 feet total depth. Snowmane was completed to 8,122 feet TD with a total vertical depth of 4,125 feet. The next two wells Firefoot and Asfaloth were drilled farther west in Petroleum County, he continues. Firefoot had a TD of 4,850 feet. Initial production did not indicate commercial wells, although they did produce oil at low rates, which Beiter says is typical for wells drilled early in an emerging resource play. The 10 vertical expansion wells after the first four (horizontal) wells really defined the data regionally, Beiter comments, adding that CMR is in the process of converting the vertical wells to horizontals. Chief Operating Officer Steve Lipari characterizes the data CMR has gathered as modern, comprehensive resource data. We have gathered extensive log, core, microseismic, tilt, and geochemistry data, he says. We have spent the past few years compiling this information so we could understand the play correctly from a regional standpoint. We have found reasonable consistency that demonstrates continuity over a large area with much of the geologic character needed for viability, Lipari continues. There is a fair amount of variability, like in any other system. We still are gaining an understanding of how the play is going to play out in different areas. Fracture Methodology For its production test, CMR used Bakken-style fracture stimulation because of similarities in the lithology, reports Lipari. As in any continuous shale resource play, you start with one methodology and evolve from there, he reflects. The initial jobs were cross-linked, high rate and high volume, Lipari describes. This evolved in the first half of this year into fracs that are still crosslinked, but at lower rates, small stage sizes, and moderate to large volumes. Hitting with a big hammer proved to not be the optimal method, Lipari concludes. He says the method predominately being used in the play is producing bbl/d IPs, so he feels it is heading in the right direction. The jobs have evolved to a combination of either plug-and-perf or ball-and-drop, he adds. The next step is to upscale regionally. We need to produce long enough to define a type curve, and then we will have a better feel for where the play is headed from a commercial viability standpoint, Lipari says. CMR may initiate 3-D geophysical exploration and expects to continue drilling vertical wells to expand its regional knowledge and define completion and stimulation methods. There may be some areas of the play that lend themselves to vertical wells, Lipari comments, adding that the company s vertical wells are constructed so they can be converted to horizontal if there is an economic advantage. One of the play s attractive aspects is the area s infrastructure, comments Beiter. There is refining capacity in Billings, Mt. In addition, there is a temporarily abandoned pipeline from Sumatra, Mt., that comes through the area. With additional volumes, that could turn out to be a tremendous advantage, he assesses. CMR also has substantially completed constructing a pipe yard, truck bay and office in Roundup, Mt., Beiter mentions. Early Stage Focus Focused on oil resource plays in the Rockies, Denver-based Cirque Resources LP believes it can take horizontal drilling and fracturing to oil plays, much like these technologies were deployed with success in gas plays. President and CEO Peter Dea describes Cirque as a build and sell company with a strategy to get in early based on geology and engineering, then turn ideas over to the land department and have it lease 50, ,000 acres on any given project. For risk management, the company brings in a 50 percent working interest partner on each project. After one to three exploration wells, Dea says Cirque proves the concept and sells. We understand the value of building large, long-term consolidated leasehold positions so that once you find what you are seeking, the company has a lot of long-term, low-risk, low-cost develop- Central Montana Resources Firefoot well was drilled to a total depth of 4,850 feet in Petroleum County, Mt. Although the well produced oil at low rates, it was not considered commercial, which CMR Chief Executive Officer Kevin Beiter says is typical for wells drilled early in an emerging resource play. The company is in the process of converting Firefoot to a horizontal.

5 Denver-based Cirque Resources LP has drilled four wells in the Mississippian Heath Shale in the Central Montana Trough. Its discovery well, the Rock Happy 33-3H-2 in Rosebud County, Mt., shown here, had initial production of 271 barrels of oil a day. The well was drilled to a total vertical depth of 5,123 feet and a total depth of 9,510 feet. ment and predictable growth ahead of it, Dea expounds. Cirque has built a leasehold of 1.3 million acres, of which 550,000 are net to Cirque after bringing in partners. He says its tight oil leaseholds are in the Heath (115,000), Niobrara/Codell (230,000) and the Mowry (140,000). Each formation typically has two projects. When we started, there weren t that many medium-to-large companies that had bona fide exploration teams focused on oil resource plays, Dea recalls. Nobody thought they would work; people were focused on gas. He says the Bakken opened the door, and subsequent plays such as the Eagle Ford and Niobrara have shown it is possible to get oil out economically with horizontal drilling. horizontal, but obtains logs and cores in the vertical section before cementing, plugging and kicking off. The company expects to drill several more wells this year, potentially shoot some 3-D seismic, and ramp up drilling next year. One of the interesting things about the Heath is that it is relatively shallow, Lloyd remarks. It has been uplifted, and drilling economics are driven down pretty low. In the area Cirque has drilled, the Heath is a 400-foot thick section of oilsaturated rock. Lloyd says it is a very rich source rock that has been documented for decades. In fact, where it outcrops in western Montana, the state even considered mining it, he mentions. There have been 145 million barrels of oil produced in the Central Montana Trough, largely sourced by the Heath Shale. Lloyd reports data from vertical wells show the presence of dolomites, limestones and carbonate-rich shales for reservoir targets. He says he believes there eventually could be three or four lateral targets. Cirque uses a water-based mud system that has been very effective and is environmentally sound, according to Lloyd. We were able to land farm it after completion, he says. On May 11, Statoil announced it had purchased stakes of as much as 50 percent in several blocks in the Heath held by Cirque Resources. According to the announcement, Cirque will be the initial operator on all the prospects. Crack The Codell In the Niobrara and Codell play, Bill Nicas, Cirque s senior vice president, land and marketing, reports Cirque Resources Brennsee project encompasses 150,000 acres net to Cirque in very northern Weld County and mostly Laramie County, Co., surrounding the Silo Field. That area has had some successful Niobrara wells and some mixed results as people tried to figure out which way to drill and how to get into the zones, he says. It is very prospective for the Codell as well. The company is planning to drill some Proving The Play Cirque has drilled four wells in the Heath, all in 2011, Dea reports. The Heath discovery well is the Rock Happy 33-3H-2 in Rosebud County, Mt., which had a TVD of 5,123 feet and a TD of 9,510 feet. Initial production was 271 bbl/d oil. The Hit Parade 31-3H in Musselshell County, Mt., with a TVD of 4,494 feet and TD of 9,617 feet, IP d at 90 bbl/d oil, Dea reports. As of mid-june, Cirque s Lucky Strike 10-4H in Garfield County, Mt., was awaiting final testing, while a fourth well, Lightner Creek, had not yet been completed. Bill Lloyd, Cirque s senior vice president of operations, says the company drills all wells with the intent of going Cirque Resources LP uses a large Poseidon tank for water storage on its Chamois 23-16H well in the western Hanna Basin in southern Wyoming. The first horizontal Niobrara well drilled in this area, the Chamois 23-16H was drilled to a total vertical depth of 4,286 feet and a total depth of 8,491 feet.

6 Codell wells, Nicas says. He explains that Cirque had the Codell concept from the beginning, but initially everyone was focused on the Niobrara. This tight sandstone has been a prolific contributor in Wattenberg along with the Niobrara. Nicas says other companies are moving north toward Cirque. Logs, cores and vertical wells show definite oil saturation in the Codell. Other potential targets not yet exploited are the Greenhorn, Niobrara C bench, and the J-Sand, he adds. We looked at the whole petroleum system, which includes the Denver and Powder River basins, Nicas says. This system has produced 3 billion barrels of oil. The Brennsee is placed strategically between the basins. The Silo Field itself has produced 10 million barrels from unstimulated horizontal wells. Nicas says the company leased all around the Silo Field area because the Niobrara and Codell clearly were saturated and had a lot of potential for horizontal wells. The block was put together twothree years ago. Nobody was looking for Rockies oil at this point, making the landman s job a little easier, he says. In the last year, Nicas says, there has been a reinvigoration in the Codell in the northern DJ Basin. Cirque also has an interest in the Hanna, Powder River and Big Horn basins. In the Hanna, Nicas says, the company spudded the Chamois No H in March, targeting the Niobrara. Located in Carbon County, Wy., this well had a TVD of 4,286 feet and a TD of 8,491 feet. Nicas says Cirque and a partner plan to drill in the Cretaceous Mowry Shale within the Powder River Basin. In the Big Horn Basin, the company and partners have drilled one Mowry well and plan a second in the third quarter. Their first well, Bottoms Up, was drilled in late 2011 to a TVD of 9,295 feet and TD of 12,775 feet. Says Dea, The company is now in a 12-month stretch where we are finishing initial proof of concept wells in each project. When we have successful wells, we test the market for each project, and if someone wants to buy, we may sell. However, development wells require a different strategy, Dea notes. Those require 3-D seismic and ramped up drilling that is beyond the scope of the company. Our strategy is to get out of the way early and turn that over to one of the larger development companies, he says. There is a scarcity of oil resource projects, Dea opines, and companies are eager to obtain large leaseholds. Improving Performance The Bonanza Creek team has been drilling vertical wells in the DJ Basin since The company is successfully applying the lessons learned from that experience to drilling horizontal wells in the Wattenberg Field, according to Executive Vice President Patrick Graham. We make engineering modifications from applying techniques we believe will be more efficient, drive down costs, and increase well performance, he says. The company has acreage in the Wattenberg Field and the North Park Basin. Approximately 17,000 acres of the Wattenberg position is covered by 3-D seismic surveys. We have geologic control through the majority of our acreage from 3-D seismic surveys and our vertical drilling program, states Graham. In areas where coverage is limited, he says the company may drill verticals to get a better understanding of the geology, and then base horizontals on the results. Verticals are sometimes the best option because they take only three to four days to drill and can be used to provide the necessary data, he explains. Bonanza Creek typically drills vertical wells in areas where both the Codell and Niobrara are present. However, Graham says he believes the Codell is an attractive option for horizontal development, saying he anticipates the company will limit the number of future vertical completions in the Codell to increase the horizontal potential. Niobrara Completions In the second half of 2011, Graham says Bonanza Creek completed four horizontal Niobrara wells in the Wattenberg. The State Antelope No. 11-2HZ was completed in July with a 4,672-foot lateral and an IP of 738 boe/d. Graham says this well was in the eastern portion of the area and was drilled first to prevent lease expiration. There were vertical wells already drilled into the deeper D-Sand when we acquired our acreage in the eastern part of the Wattenberg, he relates. We knew we had the Niobrara as a backup; we could see it on all the logs. We were encouraged that the Niobrara came on very nicely, post-fracture. We saw very good flow-back rates, reservoir pressure and IPs. Bonanza Creek s second horizontal was drilled to the west to test an area where vertical wells were completed in the Codell and Niobrara. He says the North Platte No HZ had a 3,994-foot lateral and an IP of 887 boe/d. This well had 60 percent oil content, compared with 72 percent for the first well. State Antelope No HZ was completed in October with a 3,772-foot Bonanza Creek has been drilling vertical wells in the Denver-Julesburg Basin since 2001, and is applying the lessons it learned to horizontal wells in the Wattenberg Field. The company has 26,000 net acres in the Wattenberg, of which 17,000 are covered by 3-D seismic. In areas where seismic coverage is limited, Executive Vice President Patrick Graham says Bonanza Creek may drill vertical wells to get a better understanding of the geology.

7 lateral, 78 percent oil and 886 boe/d IP. State Whitetail No HZ was completed in November with a 3,501- foot lateral, 642 boe/d IP and 76 percent oil. The State Whitetail well was completed with 12 stages, four fewer than the typical 16. Graham says the company s 2012 program is weighted to the east to satisfy lease expiry issues, and says he feels confident the company s type curve is appropriate for the entirety of its position. He says at the beginning of 2012, Bonanza Creek had 290 net horizontal Niobrara drilling locations spaced at 80 acres in the Wattenberg. During first quarter 2012, the company completed five horizontal wells in the Wattenberg. The two with the longest production history had an average 30-day rate of 541 boe/d. As of May, Graham says, the company had two horizontal and two vertical rigs running in the Wattenberg as part of its plan to drill 24 horizontal wells and 92 vertical wells over the course of the year. We are very comfortable with our results as we develop our Wattenberg acreage, Graham says. The geologic characteristics of the Niobrara appear very consistent in Bonanza Creek s area. More Potential Horizontal hydraulic-fracture stimulation treatments were set originally at 16 stages, using 4 million pounds of sand, or 250,000 pounds per stage. Graham says the pounds per stage used in the stimulation are consistent with what would be used in a single vertical Niobrara/Codell well. The same fluids, proppants and pump rates are used in both vertical and horizontal wells. After monitoring height growth and interference between offsetting stages, he says the company has increased to 18- stage fracs in its 4,000-foot laterals. We analyzed the frac job using microseismic and observed decent overlap between stages, he comments. Later this year, Graham says, Bonanza Creek will participate in an extendedreach well with a neighboring operator. Bonanza Creek has nearly 60 locations where it could place an extended reach lateral, and should the company decide to augment its 2012 capital budget, he says it will drill its first operated extended-reach well later in the year. In addition, pending approval of additional capital, Graham says the company will drill a Codell horizontal, and a Niobrara C bench horizontal well, further delineating the company s inventory potential. Graham says Bonanza Creek also is evaluating the proper spacing for drilling horizontal wells. Currently, he says the company believes 80-acre spacing is appropriate for Niobrara B bench 4,000- foot laterals, but Graham notes Noble Energy is testing downspacing to 40 acres. Graham says he believes, based on the limited drainage radius of the Niobrara, that downspacing to 40 acres is feasible, and that it represents exciting upside for Bonanza Creek. Discussing infrastructure and takeaway capacity, Graham notes that the Wattenberg has been an active oil and gas field for more than 40 years. The midstream infrastructure, he says, is more than adequate for at least the next three years. That is one of the advantages, he says, to being in the Niobrara over newer resource plays such as the Bakken, where infrastructure has been a major issue. Testing North Park Basin Bonanza Creek entered North Park in 2006 when it acquired the McCallum Field, and additions over the years have brought its net acreage in the basin to 33,000. We liked the area for the multiple horizons present over the McCallum Anticline, and we saw longer-term potential for additional Niobrara development, Graham reveals. Although EOG Resources drilled seven horizontal wells in the Niobrara, this area has been underexplored, in part because it lacks gas take-away capacity, he says. The Niobrara produces high-btu gas and a high concentration of liquids, and a pipeline will need to be installed to tie into a larger gas transportation system. Graham says he believes that should this area be as attractive as the Wattenberg Niobrara, the infrastructure problem will take care of itself because the economics will support it easily. Graham says proving the geology and the productivity of the Niobrara is Bonanza Creek s focus in the near term. We shot a 3-D seismic survey in North Park earlier in the year to assist in defining the geologic aspects of the Niobrara. Additionally, we are identifying other potential horizons using the survey, and plan a full-field development incorporating multiple horizons, he says. Graham says Bonanza Creek has a good concept of the geology across the top of the McCallum structure, thanks to well control. Deeper wells drilled on the anticline also encountered the Niobrara. He says the company s biggest concern with drilling a horizontal lateral in the Niobrara is to be sure it does not run into drilling problems. If there is a fault, for example, we want to be sure we know where the Niobrara formation rises and falls, so we can keep the well bore in the path, he remarks. Graham says Bonanza Creek has drilled three North Park test wells in the past two years. The first was a vertical test within the 3-D seismic area. It will not be completed until more is known about the geology and preferred lateral direction. The second well a vertical cased well drilled off a 2-D line has been completed. Graham says Bonanza Creek is testing one of the deeper horizons and will move up into the Niobrara in the near future. The third well was a vertical test on the southern portion of Bonanza Creek s acreage. Graham says it encountered some gas in the Frontier formation, just below the Niobrara. Later this summer, Bonanza Creek will test both the Niobrara and other potential horizons. These vertical wells will give us a good idea of what the productivity is going to be in the Niobrara and form a basis for our horizontal program, Graham comments. Our North Park horizontal program likely will begin in earnest in 2013 and continue for many years. Producing The Wattenberg Bart Brookman, senior vice president of exploration and development for PDC Energy, calls Wattenberg the company s crown jewel where it is allocating the majority of its development capital, primarily because of its liquids-rich nature and oil component. The company is focused mainly on drilling Niobrara horizontals, plus Codell refracs and Niobrara recompletions in vertical wells. It is one of the highest-quality liquid-rich drilling programs in the country, he insists. PDC has been a player in the Wattenberg Field since Through a series of acquisitions, Brookman says the company s acreage position has grown to 103,000 net acres, including its recent acquisition in the core Wattenberg area. This

8 per section. He says feedback from peers and reservoir modeling indicate downspacing will work. Of course, we want to look at the results, but downspacing seems to be the industry trend and we are very optimistic about the upside, he comments. PDC Energy considers the Wattenberg its crown jewel because of its liquids-rich nature and oil component. The company owns 103,000 net acres in the Wattenberg Field, where it is focused on drilling Niobrara horizontals, plus doing Codell refractures and Niobrara recompletions in vertical wells. acquisition, which was due to close in late June, adds 35,000 acres and 700 producing wells to the company s holdings. The acquisition firmly establishes PDC as the third largest operator in the core Wattenberg area, Brookman states. We will operate approximately 2,500 vertical well bores in the Codell and Niobrara, post-acquisition, and are drilling our 30th horizontal Niobrara well, Brookman observed in mid-june. He says the company has a single rig drilling Niobrara horizontals as its primary focus, but that rig spudded PDC s first horizontal Codell well, which was to be fractured and completed in early June. PDC s Wattenberg project inventory is composed of 546 horizontal drilling locations, 1,400 vertical drilling locations, and 1,800 refrac or recompletion projects, Brookman says. The majority of the inventory is liquids rich. We anticipate substantial upside in our inventory count as we pilot and test downspacing concepts in the Niobrara, and continue to pilot horizontal Codell projects, Brookman adds. Multistage Fractures Each of PDC s Niobrara horizontals has one lateral extending 4,000-5,000 feet. Brookman says PDC is landing its laterals in the B bench of the Niobrara and is executing frac stages. Several microseismic projects early in the program helped with frac orientation and placement. The technology is used selectively, he notes, depending on available listening wells and coordination between engineering and geology teams. Brookman says PDC is running a packer and sleeve system to isolate individual frac stages. Frac jobs involve 3.6 million pounds of sand and 60,000 barrels of fluid. He says the company is drilling wells in less than 10 days and fracturing all stages in less than 24 hours, averaging 45 days from spud to first sale. PDC s horizontal Niobrara wells produce percent oil and natural gas liquids, he mentions. We originally thought a north/south orientation was optimum, but as we watched peers and our own wells, we have learned that orientation is not as big a driver as we thought, Brookman reveals. He says key drivers instead appear to be placing the lateral in the proper zones, executing the completion, and flow-back and production practices early in the life of the well. Brookman says PDC will be adding a second rig in the Wattenberg in August and plans to activate a third rig in Its inventory is built on five gross (four net) horizontal wells per section. Down - spacing pilots are planned in the Codell and Niobrara, utilizing a stacked model. Drilling commenced in mid-june. Brookman says PDC also will be testing a staggered downspacing model in late summer that features 12 gross (11 net) wells Beyond The Core Outside the core, Brookman says PDC does not consider the horizontal Niobrara a blanket play. There have been some hot spots, but also a lot of areas where horizontal Niobrara results have not been stellar, he acknowledges. PDC s model from early stages indicated we had to be very selective about acreage outside the core. PDC has 6,000 net acres in the Kreiger prospect, which is eight miles northeast of the Wattenberg core. It is prospective for horizontal Niobrara, Brookman says, and is very similar to the northeast portion of the core Wattenberg in terms of the gas-to-oil ratio. He says PDC entered Kreiger two years ago and has drilled three wells. The results were less than the core area in IP and reserves. From the geologic model, Brookman says PDC expected a different production profile, based more on natural and induced fractures. We knew we were dealing with a different geologic model. We thought we were in one of the better prospective acreage blocks outside the core, he says. It hasn t been as big a capital focus because the core Wattenberg results have been much better, and most of our acreage is in the core area. PDC also has a very large inventory of refrac/recompletion projects, which run about $200,000 per stage, Brookman reports. He says there are several work - over rigs dedicated to this program in the basin, and PDC is planning to align its refrac/recompletion activity with its horizontal drilling program. We want to frac everything around a horizontal well at the same time so that we don t have to come back and risk frac communication between a horizontal well bore and a refrac or recompletion, he explains. Atlantic Rim Opportunities Coalbed methane brought Double Eagle Petroleum to the Atlantic Rim in the eastern portion of the Green River Basin, but the company is hopeful it could yield oil as well. John Campbell, investor relations representative, says the rim represents a large exposure through the middle of Double Eagle s field, which is

9 adjacent to a Niobrara producing area. He reports the company s first Niobrara test was an exploratory well cased to 9,450 feet. The vertical well bore was drilled large enough that it could be converted to horizontal, if that proved to be the best strategy. Meanwhile, Campbell says Double Eagle has run a suite of well logs to complement 2-D and 3-D seismic shot over 20 square miles. We selected this location after reprocessing 3-D seismic and reviewing log data from wells in the area, he says. Campbell says the shale appears to be oil charged with natural fractures, according to preliminary results. Target formations are the Niobrara from 6,800 to 8,300 feet, the Frontier formation at 8,700 feet, and the Dakota formation at 9,350 feet. The Niobrara is more than 1,500 feet thick in our area, Campbell reveals. We believe the key to success will be in how we complete the wells. The Niobrara is not consistent, he observes, and can display different pressures, total organic content, porosity and permeability from one area to another. Double Eagle plans to complete its first well in August, once wildlife stipulations are lifted. The plan calls for perforation and fracturing in up to eight stages, including as many as five in the targeted oil zones, which are feet in gross thickness, Campbell says. He adds that the company also has leaseholds in the Powder River Basin that could someday be a target. Right now, he says, Double Eagle is watching its neighbors to learn from their experiences. The company owns more than 74,000 net acres in the Niobrara oil window, including 38,000 in the Atlantic Rim, 11,000 in the DJ Basin, 16,300 in the Powder River Basin, and 8,700 in the Laramie and Hanna basins. and exploit model, he remarks. We were attracted to the resource. Around that time, he continues, a couple companies were starting to find success in the western part of the Williston Basin, and specifically in Montana, with advancements in horizontal drilling and early stage fracturing. Dundas says Enerplus stepped into the play by acquiring a company that held 45,000 net acres in the Elm Coulee Field. The company had proved the horizontal play, but there still were questions about longevity, ultimate scope of resource, and the best way to optimize operations, he says. The field was producing 7,000 bbl/d with one well per spacing unit. We believed we could keep production flat by adding a well to each unit, Dundas recalls. Results exceeded expectations, he reports, and Enerplus was able to boost its production to more than 10,000 bbl/d through better well performance. The company since has drilled as many as four wells per section. Dundas says it took a while for people to start thinking about the Bakken as a world-class resource as opposed to a unique individual pool. Geologically, Montana has slightly better permeability and porosity than exists in many areas in North Dakota. It was developed with a very early and less efficient frac system than is now in use, Dundas observes. We were not doing isolated multistage fracs. By today s standards, the formation was understimulated and overcompleted. The next stage is to determine if there is a secondary or tertiary recovery opportunity. Tier One Asset In , Dundas says Enerplus began adding early stage assets to its portfolio, acquiring 74,000 net acres in Fort Berthold, N.D. This gave the company another position in the Bakken that had additional exposure to the Three Forks formation. We believed this was a tier one asset, even though there was only modest production, Dundas remembers. Since the acquisition, we have had tremendous success and plan to double production this year over last. Because of the advancements made in shale plays generally, Dundas says it is easy to forget that it is still quite early in the industry s understanding of how these resources are going to perform over time. We know a lot more than we did five years ago, but a lot of what we know is from gas plays, he avers. In the case of Fort Berthold, we are in the advanced stages of delineation now and know pretty well what resource exists. We are testing higher density well spacing, Dundas says. He says he believes the key questions Efficiencies In The Bakken For Enerplus Corporation, the payoff in the Bakken and Three Forks formations lies in gaining efficiencies within its properties. Downspacing, horizontal drilling and fracturing are strategies Chief Operating Officer and Executive Vice President Ian Dundas says the company is employing to get the most out of its leaseholds. Enerplus entered the U.S. portion of the Bakken in Dundas says Sleeping Giant was one of the earliest and largest onshore fields in 50 years. At the time, we were operating on an acquire Enerplus Corporation was an early player in the Bakken Shale with its development of the Elm Coulee Field in eastern Montana. When Enerplus acquired 45,000 net acres in the field in 2005, it was producing 7,000 barrels a day from one well per spacing unit. By adding a well to each unit and through better well performance, Enerplus Executive Vice President Ian Dundas says the company was able to boost production to 10,000 bbl/d.

10 Enerplus Corporation has targeted a 2012 capital expenditure program of $300 million for the Fort Berthold Indian Reservation in North Dakota. The company acquired 74,000 net acres in Fort Berthold in , giving it another position in the Bakken Shale that had additional exposure to the Three Forks formation. and opportunities revolve around down - spacing, recovery factors, volume of resource managed, and other potential contributing zones. Some zones may be accessible by a single well bore, but others will need specific development, Dundas speculates. He says Enerplus has been testing a series of configurations, and its most dense development has been four wells in a spacing unit. Our view is that time and technology will facilitate additional development, Dundas concludes. We are taking a measured approach and don t want to outrun our headlights. Enerplus has more than 130 drilling locations, and Dundas says the large majority of its wells will be long laterals, except when there are land issues. The wells will take advantage of multiple zones. We have feet of separation between the Three Forks and the Bakken, he remarks. That shale barrier is not really a barrier. If we land in one, we stimulate into the other. Dundas says he expects Enerplus total Bakken production to grow by 30 percent, to 22,000 boe/d, by year-end. Pivot To Oil Coming into 2012, Magnum Hunter Resources was a much more gas-weighted company with a stated goal to shift rapidly into oil in order to pursue higher commodity prices for its product. The company executed two strategic acquisitions that by midyear had changed its resource mix dramatically. In the first quarter, we were 35 percent crude oil and 65 percent natural gas, reports Chairman and CEO Gary C. Evans. Because of our acquisition efforts and redirected capital drilling program this year, we will shift that production mix completely around to 65 percent crude oil and 35 percent natural gas by year-end. He adds that Magnum Hunter started the year at 10,000 boe/d and expects to exit north of 18,000 boe/d. Magnum Hunter s Eagle acquisition, which was completed in March, brought the company 15,500 gross acres in the Williston Basin, Evans says. The $52.9 million acquisition included 191 wells producing 350 boe/d net from the Madison formation and 2.1 million boe estimated total proved reserves. More importantly though, he says, is the Bakken/Three Forks Sanish (TFS) potential associated with this acreage came at no cost. In May, Evans continues, Magnum Hunter closed on a much larger Williston Basin acquisition located in Divide County, N.D., that increased the company s working interest in Bakken/TFS properties and added 50,414 net acres, of which 17,745 (34 percent) are unitized. Estimated total proved reserves are 8.6 million boe (93 percent crude oil) with a present value of $150 million, he observes. The company previously owned a nonoperated 10 percent working interest in the properties. Consequently, Evans says, We knew the potential upside of these properties very well. The first commercially successful well in the North Dakota Bakken that was drilled horizontally and fracture stimulated was completed in Divide County in 2004, he points out. Magnum Hunter s acquisition included 44,000 net undeveloped acres and 800 gross drilling locations, Evans continues. While the current targets are Bakken/TFS, he says the company also has exposure to the Lodgepole and potentially other deeper horizons in this undeveloped acreage position. For now, the bulk of Magnum Hunter s acquisitions are completed, according to Evans. The company has 92,056 net acres in North Dakota and 32,944 net acres in the Tableland Field of Saskatchewan, Canada, for a total of 125,000 net acres in the Williston Basin. Over the past three years, we have built the size of the company substantially from both a leasehold position as well as proved and potential reserves. We believe we now have the portfolio necessary to fuel our future growth, with the possible exception of some tactical bolt-on acquisitions in one of our three core shale plays. Driving Down Costs Evans says Magnum Hunter has set an aggressive goal of driving lifting costs to below $8 a barrel. We already have driven down lifting costs to less than $10 a barrel from a high of $31, he proclaims. We did that by not only drilling higher volume wells, but also by shedding high-lifting-cost properties, as well as cutting field operating costs. Among the efficiencies Evans cites are central battery systems, commercial disposal wells with everything pipelined to one location, and electrification. As you build your presence and scope of operation in a specific field, you have the opportunity to spend the money for infrastructure in order to reduce overall cost, he says. Evans adds that Magnum Hunter also has honed its completion program, where the company now runs more frac stages with smaller volumes of fluid and sand. A typical 4,000-foot lateral has up to 30 frac stages using a resin-based sand that keeps costs low. Thus far, Evans says, Magnum Hunter has drilled more than 100 horizontal wells. He says pad drilling is a potential future efficiency driver, but leasehold expiry issues have kept the company from implementing it in all three shale plays. Our goal is to eventually do pad drilling throughout the Williston Basin, Evans attests. The company has engaged Oneok Midstream to provide gas gathering infrastructure. He says the gas is very rich at more than 1,700 Btu, but until now, it

11 has been flared. There just hasn t been sufficient volumes and infrastructure to gather this casinghead gas, Evans intones. Now there are enough wells to justify installing a gathering system, and we will be able to market the casinghead gas early next year, which equates to approximately 1,000 Boe per day net to our ownership interest. Evans says he believes there is a lot more oil in the Bakken than most people believe. The Williston Basin is estimated to hold 24 billion barrels of oil. We are recovering such a small percentage of the oil in place, even with new technology and completion techniques that have allowed us to get better and smarter, he assesses. Decline curves on new wells are much less than predicted by third party reservoir engineers. Additionally, secondary and tertiary recovery are still ahead of us and yet to be developed. This region is going to be a money maker for many years to come.