Southwestern Energy Purchases 312,000 Acres from Quicksilver In Niobrara Shale

HOUSTON, March 5, 2014 /PRNewswire/ -- Southwestern Energy Company (NYSE: SWN), through its wholly owned subsidiary Southwestern Energy Production Company, today announced that it has signed an agreement to purchase approximately 312,000 net acres in northwest Colorado targeting crude oil, natural gas liquids and natural gas contained in the Niobrara formation from Quicksilver Resources Inc. (NYSE: KWK) and SWEPI LP, a wholly owned subsidiary of Royal Dutch Shell plc (NYSE: RDS.A) for approximately $180 million, subject to closing conditions.

     

 Southwestern intends to use its revolving credit facility to finance the acquisition. The transaction is expected to close in the second quarter of 2014.

"We are very excited about our entry into this emerging liquids-rich resource play," stated Steve Mueller, President and Chief Executive Officer of Southwestern Energy. "This acreage position covers a substantial area in the Sand Wash Basin -- over 50 miles across and over 20 miles wide -- and provides the opportunity for us to leverage our operational strengths into a new large, scalable project. Basin characteristics include proven oil production with minimal water cut, preferred fluid-phase windows, demonstrated overpressure, evidence of matrix permeability and porosity from petrophysics and well decline behavior, a thick, continuous reservoir with ample storage capacity and potential upside from downspacing and stacked reservoir benches. Upon closing, we expect that we could begin drilling operations as early as June of this year."

Southwestern Energy Company is an independent energy company whose wholly-owned subsidiaries are engaged in natural gas and oil exploration, development and production, natural gas gathering and marketing. Additional information on the company can be found on the Internet at http://www.swn.com.

All statements, other than historical facts and financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the company's future operations, are forward-looking statements. Although the company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. The company has no obligation and makes no undertaking to publicly update or revise any forward-looking statements, other than to the extent set forth below. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect the company's operations, markets, products, services and prices and cause its actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause the company's actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis differentials); the company's ability to transport its production to the most favorable markets or at all; the timing and extent of the company's success in discovering, developing, producing and estimating reserves; the economic viability of, and the company's success in drilling, the company's large acreage position in the Fayetteville Shale play, overall as well as relative to other productive shale gas areas; the company's ability to fund the company's planned capital investments; the impact of federal, state and local government regulation, including any legislation relating to hydraulic fracturing, the climate or over the counter derivatives; the company's ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale play and the Marcellus Shale play; the costs and availability of oil field personnel services and drilling supplies, raw materials, and equipment and services; the company's future property acquisition or divestiture activities; increased competition; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets, changes in interest rates and the ability of the company's lenders to provide it with funds as agreed; credit risk relating to the risk of loss as a result of non-performance by the company's counterparties and any other factors listed in the reports the company has filed and may file with the Securities and Exchange Commission (SEC). For additional information with respect to certain of these and other factors, see the reports filed by the company with the SEC. The company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

SOURCE Southwestern Energy Company

Case Study via SLB: MicroScope Resistivity Niobrara Shale

via http://www.slb.com/resources/case_studies/drilling/microscope_niobrara_shale.aspx

Case Study: MicroScope Resistivity and Imaging Enable Successful Completion in Complex Shale Formation

Real-time high-resolution images accurately identify formation dip, faults, and natural fractures for placement of lateral within Niobrara target zone

Challenge: Maximize wellbore intersection with natural fractures to optimize oil recovery from highly faulted zone in Niobrara shale.

Solution: Use real-time images from MicroScope resistivity- and imaging-while-drilling service to confirm borehole position relative to target formation and identify and characterize natural fractures.

Result: Successfully placed horizontal lateral within predefined target interval and completed well for production.

previous

A MicroScope horizontal borehole image acquired while drilling is shown here with correlated dip data.

Intersect maximum number of natural fractures

An independent operator in the western US planned to drill a horizontal lateral to produce oil from a complex reservoir in the Niobrara shale formation. Prior to drilling the lateral, a complete openhole log, including images from an FMI fullbore formation microimager, was acquired in a vertical well to identify the best horizontal target interval, confirm the presence of natural fractures, and determine the maximum horizontal stress orientation.

This information was used to select the direction the horizontal lateral should be drilled to maximize the number of natural fractures it would intersect and facilitate the development of a complex fracture network during stimulation. To enhance reservoir understanding and optimize oil recovery, the operator needed to correlate and confirm the position of the borehole relative to the target formation while drilling.

Optimize wellbore placement in highly complex reservoir

MicroScope service provided high-resolution electrical borehole images, azimuthal gamma ray measurements, and multidepth formation resistivity measurements in real time. This information, together with mud gas data, was used to constantly update the structural model and determine wellbore trajectory relative to the target interval in the highly faulted reservoir.

When the lateral had been drilled to about three-quarters of its planned length, it crossed a major fault plane with a significant fault throw, which placed the lateral below the target formation within just a few hundred feet of TD. To improve reservoir exposure, the operator decided to drill a sidetrack from the existing lateral.

Improve structural understanding

The improved structural understanding that interpretation of the real-time MicroScope images provided made steering the sidetrack less demanding than steering the original lateral. While drilling the sidetrack, real-time MicroScope images revealed that there was less structural change than there had been in the first half of the lateral. Constant updating of the structural model based on real-time data enabled successful placement within the predefined target interval and well completion.

Download: MicroScope Resistivity and Imaging Enable Successful Completion in Complex Shale Formation (0.91 MB PDF)

VIA HTTP://WWW.NCBR.COM/ARTICLE/20130129/NEWS/130129915

Niobrara oil deals surged in 2012

written by:  Steve Lynn

The value of oil and natural-gas mergers and acquisitions in the Niobrara shale formation totaled nearly $4 billion in 2012, according to the accounting firm PricewaterhouseCoopers. 

The value of the three Niobrara deals in 2012 more than doubled the $1.4 billion value of the four deals struck in 2011, PwC told the Business Report. 



More than $3.6 billion came from two deals that closed in the fourth quarter of 2012. PwC has a policy not to name companies involved in the deals. 

One deal includes a combination of assets in the Piceance Basin in northwest Colorado and the Niobrara formation in the Denver-Julesburg Basin. 

"If you look at the interest in the Niobrara, it's really been up for 2012 and continues in the fourth quarter with two significant deals," said Rowena Cipriano-Reyes, a Denver-based partner with PwC's energy practice. 

The size of the deals stems from companies' desire to diversify their assets as well as horizontal oil drilling opportunities, she said. Companies that focus on natural-gas drilling, for example, have sought to enter the Niobrara for shale oil. 

Deals in the Niobrara come as Rocky Mountain oil and gas transactions set fourth-quarter and 2012 records. PwC reported 15 deals totaling $9.9 billion in the fourth quarter and 38 deals worth $22.8 billion in 2012. 

"Similar to the national trend, those with assets in the Rockies accelerated their deal plans toward the end of the year due to the pending fiscal cliff," Cipriano-Reyes said. "Looking forward we believe deal activity will continue at similar levels, with the potential of private equity more actively pursuing deals here."

The most active shale plays for deals with values greater than $50 million during the fourth quarter include the Bakken in North Dakota, which saw seven deals totaling $4.1 billion. 

Nationwide, oil and gas merger and acquisition activity during the fourth quarter of 2012 came to 75 deals totaling $56.2 billion, the second-highest level seen in a decade. 

The flurry of fourth-quarter activity pushed overall deal volume in 2012 to 204 transactions for deals valued at over $50 million. The deals totaled $146.2 billion, also the second-highest total deal value in 10 years.

Water is Now in Niobrara Shale Area

By David A. Hill, Executive Editor  at Colorado Energy News

Doug White will tell anyone who will listen that “wastewater recycling is happening now, every day in the Niobrara.” He’s not blowing smoke.

As Vice President of High Sierra Water Services’ business in Colorado, Doug sees the daily progress his company is making
in this critical area, and how it is positively impacting water management in the increasingly thirsty Denver/Julesburg
(DJ) Basin.

This good news story, however, isn’t widely known, even among the oil and gas choir. In fact, at this year’s COGAEpicenter Conference, White and his colleagues had a hard time containing themselves when a speaker-attendee panel included dialogue that urged that water recycling get started in the Niobrara.

“We looked at each other, and wanted to shout out … ‘Hey, it’s already here, and we’re doing it successfully every day, for the industry and the environment,’ “ he explains.

Rest assured, Niobrara Report is here to get the word out, Doug.

The High Sierra name has been in the news this year. This past spring Denver’s High Sierra Energy LP and its general partner, High Sierra Energy GP LLC, were acquired by NGL Energy Partners LP of Tulsa, Oklahoma for about $583 million. High Sierra Water Services, LLC is a core business segment for the company, with seven disposal plants operating in Weld County, two of which include water treatment and recycling capabilities of up to 20,000 barrels per day. Their customers are the oil and gas production companies that are producing in the basin.

THE BEGINNING

To get the true picture of produced water handling and recycling in the Niobrara, you’ve got to go back to its roots, and that means Bruce White (no relation to Doug), a fourth generation Coloradoan from Ault. Bruce got his first taste of the oil and gas industry in the early 80’s as an investor, and then in 1984 raised enough money from family and friends for his first well, which was the beginning of Conquest Oil Company. The company’s well ownership grew, but interestingly, it was the water side of the business that intrigued Doug and his partner, Dale Butcher, the most.

The fact that all oil and gas drilling operations produce a wastewater byproduct that is regulated by the state was seen as an opportunity by White and Butcher. “Over time, we became more and more interested in water handling issues and recycling, and we eventually became convinced that it was the future of our company,” Bruce explains.

White and Butcher used a business model that was the opposite of oil drillers. Conquest sought dry holes, deep dry holes, in which they could inject the produced water from drilling in the DJ Basin.

Before Conquest Water Services came along, the water produced from Weld County’s wells was stored in evaporation pits, which regulators regarded as environmentally hazardous.

“We were the first commercial water production facility in Weld County to inject (water into the ground),” White points out. Conquest eventually took in between 80 to 90 percent of the water produced by Weld County wells. “The process involves injecting the water 10,000 to 12,000 feet down, into a sandy, porous reservoir ─ a big ocean bottom,” he adds.

GEARING UP AT THE RIGHT TIME

High Sierra’s purchase of Conquest in 2011 injected money, management and technology into the efforts to bring real scalability to wastewater disposal and recycling in the Niobrara. Today, the company employs 100 people at its facilities across the DJ Basin, with three shifts of three people working the injection disposal operations 24/7. A total of eight injections wells are owned by High Sierra, and they are currently drilling an additional two wells in the next six months

Horizontal drilling is king in the Niobrara, and that means a greater water demand for more fracs and completions. In a drought-stricken year, High Sierra’s ramp-up of it water treatment operations couldn’t come at a better time — for the industry and our environment.

“With fewer water resources available to municipalities and industry and other stakeholders in Colorado, the ability to recycle wastewater that producers and service companies can purchase for use in new frac jobs becomes even more important,” according to White. “They buy less water, which is a good thing, obviously.”

for complete coverage  http://coloradoenergynews.com/2012/11/the-future-now-water-recycling-niobrara/

AN EXPANDING FOOTPRINT

Operators of the High Sierra water treatment facilities are state-licensed water and wastewater operators, with significant municipal and industrial expertise. All told, the company has a wastewater disposal capacity of 50,000 barrels per day (BPD), with commercial disposal capacity in the D/J Basin of 65,000 BPD. Recycling capacity is currently 20,000 BPD, but the company says the figure can increase to 30,000 depending on incoming water quality.

High Sierra accepts Class II oilfield wastewater from more than 100 customers in the DJ Basin, spanning a nearly 100-mile radius. “We are either injecting or recycling it from more than 17,000 wells out of a total of more than 22,000 in the Basin. Measured by anyone’s standards, this is an impressive percentage.

TOUR DE FORCE

Niobrara Report magazine was recently invited to tour the company’s C-7 disposal well and recycling facility on County Road 74 and Highway 398 in Weld County. The “Big Hat, No Cattle” acronym clearly does not fit to this operation, where a small modular office is overwhelmed by large water tanks, loading docks, trucks, pipelines and a high-tech recycling center. Out on the dry, dusty fields of eastern Colorado, wastewater injection wells and recycling get top billing, and cushy offices are elsewhere.

White and his team are particularly proud of their efforts here. “We’re now recycling 6,000 barrels of produced and flowback water daily and have the capability of doing up to 20,000 barrels a day,” he explained during our on-site visit. “What’s more, we know where every barrel of wastewater comes from because we track it back from the well and report it to the regulators and our customers.”

The insides of the recycling facility feature a maze of piping, tanks, pumps, and filters all being monitored by licensed operators from computer consoles. The highly engineered system would impress even the most ardent techno geek, maybe even environmentalists, if they dare venture out this way. Their method includes both mechanical and chemical processes to effectively turn wastewater into a clear saltwater, which can be reused by the drilling companies to drill and frac new wells. High Sierra has worked hand in hand with the major operators to produce water that is fully compatible with drilling and frac fluid chemistries.

“Engineers lead the recycling efforts here,” says White, who came to his current position from the corporate side of High Sierra. “Their backgrounds are in wastewater treatment, not oil and gas. Our combined experience from water treatment and the oil field has brought us to where we are today.”

GREEN IMPRINT ON REGION

The Weld County plants are not High Sierra’s only imprint on the region. Crafting better solutions for produced water recycling is the job description at High Sierra’s research facility in Commerce City, because, as White, reminds us, water is different in each shale play. “We have been recycling gas field wastewater in Western Wyoming for more than four years and have returned almost 32 million barrels to the field for reuse.”

The “green “benefits don’t end at the water’s edge. Recycling practices at High Sierra’s Briggsdale and Grover plants in Weld County are eliminating more than two million miles a year of truck traffic. The strategic locations near several high activity areas of production have saved both impact on the roads and bridges and truck emissions.

The locations of the facilities were not by accident but strategically planned to provide efficiencies in water transport operations.

In close proximity to heavily populated communities in the Front Range of Colorado, the arid Niobrara has its own set of water issues that impact all stakeholders in the region. Improving the management of this precious commodity is essential for our citizens and the environment. Fortunately, High Sierra Water Services is doing just that, while meeting the needs of a growing industry. That benefits everyone.

True Grid Paver Erosion Prevention on Well Site

http://truegridpaver.com/environment       

Seeking input on viability of this product for drilling, production, terminals, well sites, and Repair/Maint Facilities within the Energy Sector...

Email input to energyehs@gmail.com

www.truegridpaver.com

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Environment

TrueGrid is designed and manufactured to be true to the specifications of your project, and true to the sustainability of our environment.

STORM WATER MANAGEMENT

Storm water runoff is generated when precipitation from rain and snowmelt events flows over land or impervious surfaces and does not percolate into the ground. As the runoff flows over the land or impervious surfaces (paved streets, parking lots, and building rooftops), it accumulates debris, chemicals, sediment or other pollutants that could adversely affect water quality if the runoff is discharged untreated.

TrueGrid is a pervious paving solution that allows the storm water to infiltrate through to the soil and replenish natural aquifers.

EROSION CONTROL

The installation of TrueGrid safeguards from erosion due to vehicle traffic, pedestrian traffic, rainfall, and flooding waterway currents. TrueGrid holds your filler material in place preventing displacement and interblending. The savings from constant repairs to an eroded environment and from the replacing of paving material is valuable to your company’s bottom line. However, the saving from more wear and tear to the environment is the true benefit of using TrueGrid as a paving solution.

HEAT ISLAND EFFECT

What is “Heat Island Effect”? 
Heat Island Effect occurs in areas such as a city and industrial sites that have consistently higher temperatures than surrounding areas because of greater retention of heat. This retention of heat is due to buildings, concrete, and asphalt.
Using TrueGrid in these “hot spot” areas for pathways, parking lots, driveways, roofs…etc., reduces the absorbability of solar rays and thus helps steady and cool the natural environment.

MANUFACTURED FROM 100% RECYCLED PLASTIC

TrueGrid is made of 100% recycled plastic, and can also be recycled itself. Reducing the amount of new plastic and reusing existing plastic, is very important to the sustainability of the environment. The conscience effort to use products that add to the sustainability of the environment, gives a company a high level of credibility.

 

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Summary: Final EPA Air Rules for Nat Gas Drilling

   EPA orders "Green Completions"  for Frac Natural Gas Wells

 Thursday, April 19, 2012

Breaking News – EPA Issues Final Air Rules for Oil and Gas Industry, but delays until January 2015 the requirement to reduce emissions during operations using so-called green completion equipment. 

 

Here is Summary of Key Changes to EPA Air Rules 

EPA’s Air Rules for the Oil & Natural Gas Industry

SUMMARY OF KEY CHANGES TO THE NEW SOURCE PERFORMANCE STANDARDS

On April 17, 2012, the U.S. Environmental Protection Agency (EPA) issued cost-effective regulations, required by the Clean Air Act, to reduce harmful air pollution from the oil and natural gas industry while allowing continued, responsible growth in U.S. oil and natural gas production. The final rules include the first federal air standards for natural gas wells that are hydraulically fractured, along with requirements for several other sources of pollution in the oil and gas industry for which there are currently no federal standards. The rules for fractured gas wells rely on proven, cost-effective technology and practices used by industry leaders today, including those in EPA’s Natural Gas STAR Program.

After considering the extensive comments received on the proposed rule, the final rule increases compliance flexibility for well owners and operators; streamlines notification, reporting, and recordkeeping; avoids unnecessary spending of state and private resources; enhances transparency and accountability; and maintains comparable environmental benefits.

KEY PROVISIONS IN THE FINAL RULE 

Green completions, also called reduced emission completions (or RECs), continue to be identified as the best system of emission reduction, but EPA has identified a transition period (until January 1, 2015) to ensure green completion equipment is broadly available. During this transition period, fractured and refractured wells must reduce their emissions through combustion devices (flares). To recognize the leadership of owners and operators who have already adopted green completions as a best management practice and to encourage others to become early adopters, while at the same time eliminating unnecessary expenditures of state resources, the final rule redefines actions that constitute modifications under the New Source Performance Standard program (NSPS).

COMMENTS SUBMITTED ON THE PROPOSED RULE Substantive comments were received on the proposed rule including a significant amount of new data. This information focused on a number of key issues, including:

o The intended breadth and impact of the rule including clarification of the definitions of natural gas well and reduced emission completions;

o The technical feasibility and cost effectiveness of reduced emission completions, including the availability of equipment need to perform green completions;

o The rule’s alignment with existing state permitting programs;

o The advisability of pre-notification and annual reporting requirements; and

o A variety of technical issues related to proposed controls of pipeline gas, pneumatic controllers, and storage tanks.

CHANGES MADE IN THE FINAL RULE

The definition of natural gas well was clarified.

o In response to questions about the intended breadth of the rule, the definition of a natural gas well was expanded to provide more certainty to the regulated community as well as state regulators. Language was added to identify key indicators of natural gas wells, including the availability of appropriate gas collection infrastructure as well as drilling locations within the four geologic formation types generally accepted as gas-producing. The four formation types are high permeability gas, shale gas, other tight reservoir rock, and coal seam.

The definition of green completion was clarified to focus on performance rather than identifying specific required technology for these completions.

o The changes allow greater flexibility, lower costs, and reduced burden on equipment manufacturing and distribution, while maintaining the intended emission reductions.

Low-pressure wells were identified and exempted from green completion requirements.

o In addition to wildcat and delineation wells, the final rule exempts non-wildcat and non-delineation low-pressure wells from the need to conduct green completions because of technical infeasibility. Information gathered by EPA indicates that green completions are not feasible to conduct in approximately 87 percent of the natural gas wells fractured in coal bed methane formations. The change reduces approximately 10 percent of the fractured natural gas wells overall, which recognizes current technology limitations, lowers expected compliance costs of the rule and reduces anticipated burdens on equipment manufacturing and distribution.

A transition period was identified before green completions would be required.

o The final rule allows affected sources until January 1, 2015 before they need to conduct green completions, ensuring sufficient time for needed cost-effective control equipment and trained operators to become broadly availability. During this transition period, flaring will be required to reduce VOC emissions by 95 percent and thus preserves comparable environmental benefits.

Early adoption of green completions will be encouraged.

o The definition of modifications was revised to recognize the leadership of well owners and operators who have already adopted green completions as best management practices and to encourage others to become early adopters. Given that green completions minimize emission increases that would otherwise trigger requirements for modifications under NSPS, owners and operators of existing wells can choose to conduct refracturing activities without changing their state permit status. This revision also has the advantage of maintaining flexibility in the application of state permitting authority and resources without compromising emission reductions. Lastly, as an incentive for early installation of green completion equipment, this change could have the effect of increasing its availability in ways that benefit supply and price.

Pre-notification requirements were streamlined and annual reports were revised to enhance transparency and accountability.

o Pre-notification has been simplified to sending an email no later than 2 days prior to completion following the hydraulic fracturing or refracturing of a gas well. State pre-notification requirements were also determined to be sufficient for compliance as a way to avoid unnecessary duplication. Transparency and accountability have been enhanced by requiring a senior official to certify the accuracy of annual reports. In addition, the agency has provided more flexible and streamlined options for industry to structure their annual compliance reports, including allowing them to report emissions by company, not by source as was the case in the proposed rule.

Does not finalize requirements for compressors and pneumatic controllers in the transmission segment of this industry

o Based on public comment, the agency concluded it needed additional information in order to set cost-effective standards for compressors and controllers in this segment, where VOC content of the gas generally is low. A variety of changes were made to encourage leak reductions from existing equipment and from storage vessels in response to technical comments.

o A number of technical changes were made as a result of comments received. Most notably, the final rule exempted from regulation low-bleed controllers (with bleed rates below 6 standard cubic feet per hour) located between the well-head and the point where the gas enters the transmission line, to encourage a quicker transition from high-bleed controllers. The requirements for high-bleed controllers were also phased in over one year to give manufacturers of these devices the time needed to test and document the gas bleed rate. A different metric was also identified to simplify the determination of which storage tanks are covered by the standards. Instead of the proposed throughput measurement, the final rule identified a regulatory cutoff of 6 tons of VOC emissions annually for storage tanks. In addition, the final rule provides a one year phase-in for required storage vessel combustion devices to ensure equipment availability.

EPA Issues Final Air Rules for the Oil and Natural Gas Industry

On April 17, 2012, the U.S. Environmental Protection Agency (EPA) issued cost-effective regulations, required by the Clean Air Act, to reduce harmful air pollution from the oil and natural gas industry while allowing continued, responsible growth in U.S. oil and natural gas production. The final rules include the first federal air standards for natural gas wells that are hydraulically fractured, along with requirements for several other sources of pollution in the oil and gas industry that currently are not regulated at the federal level.  Based on public comment, EPA made a number of changes to the proposed rules to increase compliance flexibility while maintaining comparable environmental benefits, streamline notification, recordkeeping and reporting requirements, and strengthen accountability.

• Final rule (PDF) (588pp, 1.3 MB)
• Overview fact sheet (PDF) (5pp, 354k)
• Summaries of requirements for:
  • Natural gas well sites (PDF) (5pp, 411k)
  • Natural gas gathering and boosting stations (PDF) (3pp, 389k)
  • Gas processing plants (PDF) (3pp, 395k)
  • Natural gas transmission compressor stations (PDF) (2pp, 322k)
  • The oil industry (PDF) (2pp, 320k)
• Summary of key changes to the rule (PDF) (3pp, 320k)
• Regulatory Impact Analysis (PDF) (224pp, 1.8 MB)

Deadline for Final Oil and Gas Rule extended to April 17, 2012
April 2, 2012 - EPA and parties have agreed to a two-week extension – until April 17, 2012 - on a consent decree to issue final air rules for the oil and natural gas industry. The agency requested the additional time to fully address the issues raised in the more than 156,000 public comments we received on the proposed rules.

• Stipulation extending deadline for issuing final rule (PDF) (3pp, 10k) - filed April 2, 2012

EPA extends public comment period for oil and natural gas proposed rule
October 24, 2011 - EPA is granting requests for a 30-day extension to the public comment period for the Agency's proposed standards to reduce air pollution from oil and natural gas drilling operations. The public comment period will now close on November 30, 2011. The standards would rely on cost-effective existing technologies to reduce emissions that contribute to smog pollution and can cause cancer, while supporting the administration's priority of continuing to expand safe and responsible domestic oil and gas production. The standards would leverage operators' abilities to capture and sell natural gas that currently escapes into the air, resulting in more efficient operations while reducing harmful emissions that can impact air quality in surrounding areas and nearby states.
In addition, the litigants in the suit have agreed to a 35-day extension of the date for the final rule, which would extend the deadline from February 28, 2012 to April 3, 2012.

• Proposed rule extension (PDF) (2pp, 147k) - Federal Register - October 28, 2011
• Stipulation extending deadline for issuing final rule (PDF) (3pp, 11k) - filed October 28, 2011
• Summary of topics on which EPA is seeking comments (PDF) (8pp, 129k) - Topics on which EPA is specifically seeking comment in the proposed regulations for the oil and gas industry. Comments are due by November 30, 2011.

Public Hearings
August 25, 2011 - EPA will hold three public hearings on the proposed standards to reduce air pollution from the oil and natural gas industry. The hearings will be Sept. 27, 28 and 29 in Pittsburgh, Denver and Arlington, Texas

• Hearing Notice (PDF) (2pp, 184k) - Federal Register - August 26, 2011
• List of preregistered speakers
  • Pittsburgh, PA (PDF) (4pp, 213k)
    • Audio Recording of Hearing Part 1 (mp3) (21.3 MB)
    • Audio Recording of Hearing Part 2 (mp3) (17.0 MB)
    • Audio Recording of Hearing Part 3 (mp3) (13.3 MB)
    • Audio Recording of Hearing Part 4 (mp3) (13.2 MB)
    • Audio Recording of Hearing Part 5 (mp3) (20.2 MB)
    • Audio Recording of Hearing Part 6 (mp3) (25.1 MB)
  • Denver, CO (PDF) (3pp, 166k)
  • Arlington, TX (PDF) (3pp, 75k)
    • Audio Recording of Hearing Part 1 (mp3) (5.5 MB)
    • Audio Recording of Hearing Part 2 (mp3) (46.1 MB)
    • Audio Recording of Hearing Part 3 (mp3) (8.2 MB)
    • Audio Recording of Hearing Part 4 (mp3) (23.0 MB)

EPA proposes air rules for the oil and gas industry
July 28, 2011 - The U.S. Environmental Protection Agency proposed a suite of highly cost-effective standards to reduce emissions of smog-forming volatile organic compounds (VOCs) and air toxics from the oil and natural gas industry. The rules also would significantly reduce methane, a potent greenhouse gas.

• Proposed rule (PDF) (106pp, 772k) - Federal Register - August 23, 2011
• Fact sheet (PDF) (8pp, 419k)
• Overview Presentation (PDF) (15pp, 250k)
• Regulatory Impact Analysis (PDF) (204pp, 1.6 MB)

Niobrara players:

Lauren Best, Online Editor

 

A recent study by Canaccord Genuity on the Niobrara shale states that it is only a matter of time until one group (or more) finds itself on top of a delicious Niobrara treat.

The US has succeeded in providing energy companies with a plethora of rich, delightful shale sweet spots that have been continuing to satisfy even the greediest sweet tooth in the industry. The trendiest concoction of them all, the Niobrara shale, continues to harness a good portion of the attention and it seems it isn’t going to mellow out anytime soon. Taking into account recent lease sales and property acquisitions being enjoyed by a variety of companies, it will be exciting to see which one has stumbled across the golden ticket of this Rocky Mountain region.

Ahead of the gameWhile the first discovery in the Niobrara runs all the way back to 1919, a surge of interest occurred approximately 20 years ago when Union Pacific Resources Group (UPRG) developed Silo field with early horizontal-well technology. UPRG completed numerous horizontal wells in the shale until it was purchased by Anadarko Petroleum Corp. in 2000 (Anadarko currently owns 500,000 net acres in the play). UPRG’s most promising well, the #1 McGahan 21-5, drilled in Silo Field, was a harbinger of the Niobrara’s current potential.

Listen to the complimentary webinar - The Emerging Niobrara. It will cover development strategies and the future potential of this exciting shale play. Register Here

Intrigued by the success of the decades-old McGahan well, EOG Resources was the first to revisit the Niobrara formation with modern horizontal drilling and multistage fracturing technology. And, it won big. EOG bought substantial acreage (400,000 acres-worth, to be exact) at a prices of US $35 per acre. The company’s opening project in the region took place in 2007 across 100,000 acres of Colorado’s North Park Basin.

To date, EOG has reported progress on five wells in its DJ Basin program, where it has shifted its activity. Its first DJ well, #2-01H Jake, produced 50,000 bbl of oil in its first 90 days on production with an average rate of 555 boe/d. EOG’s production rates for its three completed DJ wells range from 730 to 1,558 b/d of oil, but primary blame can be attributed to the Jake well for starting all of the commotion.

Land positions snapped up“Prior to the [Niobrara craze], these areas were getting from $40 to $70 per acre. You can imagine what prices have jumped to now,” said Steven Degenfelder , senior vice president of exploration, Double Eagle Petroleum, in an interview with the Casper Star-Tribune.

Most recently, the state of Wyoming held a mineral-lease sale where officials were able to auction off $42 million worth of property to hungry bidders, according to the Casper Star-Tribune.

Big Bear Oil & Gas proved to be the auction’s big spender as it snapped up a 314-acre parcel with a bid of $3,200 per acre. The company also bought a wide array of additional properties, many that carried a per-acre price at or above $2,000. However, while some areas drew in a substantial amount of money, there were some parcels that only sold for $1 to $3 per acre.

“[The range in prices] were all geologically based on the best educated guesses we have [as to what areas hold the most potential],” said Degenfelder.

At the end of the auction, there were only 11 state leases that remained without bidders. The mineral leases that were sold will expire in five years and if oil and gas is found on any of the leased prospects, the additional severance taxes and royalties are applied that will be distributed between the federal, state, and local governments.

“That’s the name of the game - everyone benefits from actual production,” said Harold Kemp, assistant director of Wyoming’s mineral leasing and royalty compliance division.

Worried your company missed out on the action? Don’t be – Wyoming has already scheduled two additional mineral lease sales for August 4th and November 3rd of this year. Information about the two sales will be provided on the Wyoming state Web site, www.wyoming.gov.

In addition to EOG Resources and Big Bear Oil, a plethora of other companies are vying for the big find. Other big stakeholders in the Niobrara include the following:
• Noble Energy – currently holds 751,000 acres in and around Wattenberg, Lilli, Grover, and Silo fields. Its prospects in this region are projected to be its driving force in the onshore game for the next five years
• Cirque Resources LP – a private E&P firm that has 400,000 net acres in two Niobrara play areas, one near Silo Field. Cirque is currently in the process of several large-scale regional studies on its acreage.
• PDC Energy – after a recent addition of 5,500 acres, the company now holds 70,500 Niobrara acres. It plans to drill its first horizontal well in the fourth quarter of this year and continue drilling other wells into 2011 and 2012.
• Samson Oil & Gas – Samson recently announced it reached agreement to sell some 24,000 acres of its 40,000-net-acre stake in the Niobrara to a large independent for a final price between $61 and $79 million in cash. Samson’s position is in Goshen County, Wyoming, north of EOG’s acreage.

Is Niobrara the real deal?
Many companies, including EOG, are following trails of successful wells. Wattenberg and Silo fields and areas in between are seeing substantial amounts of permitting activity and preliminary drilling results remain promising.

But with all of the hype surrounding this shale, some are wondering exactly how valuable is the Niobrara region expected to be?

According to a recent report by Irene Haas, managing director, Canaccord Genuity, economic estimates of the Niobrara shale are promising. Assuming a type curve with an initial daily production rate of approximately 475 boe and a gross estimated ultimate recovery of 400,000 boe, an average $3.5-million horizontal Niobrara well will generate an internal rate of return of 66% and after tax PV-10 of $3.1 million (33% tax).

Another factor that supports Niobrara potential is a good initial track record. According to Haas, the formation takes to the stimulation process like a champ and the drilling projects that have already been completed went without hitches. Recently drilled wells have also carry an industry-pleasing time frame – on average running from 18 to 20 days. In addition, the area is extremely well mapped, making it easy to predict the gross thickness and lateral extent of the shale.

Any way you slice it when you take history and recent projects into account, the Niobrara is a promising region that will offer up numerous sweet spots to any interested party – it is just a matter of who finds them first.