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Vol. 20, No. 47 Week of November 22, 2015
Providing coverage of Alaska and northern Canada's oil and gas industry

The Producers 2015: Miller Energy Resources Ltd.

ERIC LIDJI

For Petroleum News

Miller Energy Resources Ltd. is the parent company of Cook Inlet Energy LLC and Savant Alaska LLC and operates production in Cook Inlet and on the North Slope.

The company expanded its Alaska operations quickly over the past two years and was vulnerable when global oil prices declined over the second half of 2014. Now, the Tennessee-based independent is looking for a plan to get its balance sheet in order, and is considering a range of options including selling various assets in its Alaska portfolio.

In early October 2015, as the Producers was going to print, Miller filed for reorganization with the U.S. Bankruptcy Court in Alaska.

The principals of Cook Inlet Energy LLC formed the company in 2009 to acquire Cook Inlet assets in the bankruptcy proceedings of Pacific Energy Resources Ltd. The company initially worked to revive existing properties including the West McArthur River unit, the West Foreland gas field, the offshore Redoubt unit and its Osprey platform, the Kustatan production facility and its minority stake in the onshore Three Mile Creek gas field.

A five-well workover campaign at West McArthur River in 2010 brought more than 1,100 barrel per day into production, according to the company. That summer, the company also returned the shut-in KF No. 1 well at the Kustatan field into production at some 70,000 cubic feet per day. By mid-2011, the company had returned the Osprey platform to commercial operation, bringing some 600 barrels of oil equivalent per day in initial production from two existing wells at the Redoubt unit. The company has continued to devote resources to increasing production at those fields in the years since.

In late 2013, Cook Inlet Energy acquired Armstrong Cook Inlet LLC for nearly $65 million and assumed control of the North Fork unit and associated infrastructure. In February 2014, the company acquired the Glacier No. 1 rig - now Rig 37 - for some $7 million. As oil prices fell, the purchase of a producing gas field seemed fortuitous.

In May 2014, Miller Energy announced that it would purchase Savant Alaska LLC for some $9 million. While the company originally expected to close the deal in August, the actual closing came in late 2014, after oil prices had fallen drastically from summer highs. The deal gave Miller majority ownership and operatorship of the Badami unit on the eastern North Slope.

Given the low oil prices and higher than average Alaska gas prices, Miller made a strategic shift to focus on natural gas and low-risk oil development in the short term. In late July 2015, the company said it had identified eight workover projects costing approximately $1.8 million that should increase production by 1.7 million cubic feet of gas and 220 barrels of oil per day and yield a return on investment in less than a year.

In August 2015, the U.S. Securities and Exchange Commission charged Miller Energy Resources Inc. and three people associated with the company with overvaluing its Alaska properties. Toward the end of the month, the company and the federal agency reached a tentative $5 million settlement to resolve the dispute over the next three years.

The West McArthur River unit

Stewart Petroleum Co. discovered the West McArthur River field with the W. McArthur River No. 1 well in 1991 and brought the unit on the west side of Cook Inlet into production in September 1994.

Several companies operated the west side Cook Inlet unit over the following decade and a half. Forcenergy Inc. acquired the leases in 1997. Forest Oil Corp. became the operator in late 2000 after acquiring Forcenergy. In 2007, Forest sold the unit to Pacific Energy Resources Ltd., which sold the unit to Cook Inlet Energy in a 2009 bankruptcy auction.

Cook Inlet Energy spent some $7 million in 2010 working over five West McArthur River unit wells: WMRU-5 in March, WMRU-6 in April, WMRU-1A in May, WMRU-7A in June and the shut-in WMRU-2A toward the end of the year. The work brought more than 1,100 barrels of oil equivalent per day online, according to the company, and made WMRU-2A available for a future waterflood pilot program to enhance oil recovery.

The company drilled two wells at the unit in 2014. The 15,535-foot WMRU-8 had a primary target in the Hemlock and a secondary target in the pre-tertiary Jurassic oil zone, which some geologists consider to be the source rock for Hemlock and West Foreland oil reservoirs across the Cook Inlet region. The 14,470-foot WMRU-2B sidetrack came online in June 2014 at an initial rate of 630 barrels of oil equivalent per day.

At the West McArthur River unit, Cook Inlet Energy has “determined that sidetracking holds the best opportunity to restore and increase production,” according to a January 2015 plan of development. Specifically, the company told state officials it would sidetrack the shut-in WMRU No. 1A and No. 7A sidetracks and was evaluating the producing WMRU No. 8 well as a sidetrack candidate.

Future plans for West McArthur River focus on two exploration prospects, which Cook Inlet Energy calls Sword and Sabre. The company is still evaluating both projects, according to the plan of development. Information from the Sword No. 1 exploration well will inform the plan for a Sword No. 2 appraisal well, which the company has tentatively slated for April 2017. Cook Inlet Energy is “still evaluating” plans for Sabre, although, as an extended reach exploration well, the prospect conflicts with the current strategy of “developing lower risk targets,” according to the company. The company expects to delay work until after it finishes developing proven prospects and may seek out a partner.

Through July 2015, the West McArthur River unit had produced more than 14 million barrels of oil, according to the Alaska Oil and Gas Conservation Commission.

The Redoubt unit

Pan American Petroleum Corp. discovered the Redoubt Shoal oil field in 1968 with the Redoubt Shoal Unit No. 2 well. Forcenergy and Union Oil Company of California initially partnered on a plan in the late 1990s to bring the offshore field into production but the effort was delayed after Unocal backed away from the project. Forcenergy merged with Forest Oil in 2000 and the expanded company installed the Osprey platform in 2001 and brought it into operation in 2002.

The platform had been the newest in Cook Inlet until Furie Operating Alaska LLC installed the Julius R platform at its offshore Kitchen Lights unit earlier this year.

The Redoubt unit includes the Osprey platform and the Kustatan production facilities.

The unit and the platform were offline when Cook Inlet Energy acquired the prospect in 2009. The company brought the facilities back into production in mid-2011 by replacing electric submersible pumps in the RU-1 and RU-7 wells. The company later shut-in RU-1 because of an equipment problem, but the RU-7 well continued to produce regularly.

Using its newly purchased Rig 35, Cook Inlet Energy worked over RU-1 in August 2012, removing some 31,000 pounds of junk from the wellbore to bring the well back online at an initial production rate of 482 bpd. In late 2012 and early 2013, the company worked over RU-3 and RU-4A, a pair of natural gas wells needed for operational fuel. RU-3 faced some complications, but RU-4A tested at a peak rate of 1.7 million cubic feet per day, which allowed Cook Inlet Energy to suspend some $500,000 in monthly third-party fuel deliveries. By early summer, the company was selling excess gas into the market.

In June 2013, Cook Inlet Energy more than doubled its total Alaska crude production by bringing the RU-2A sidetrack online at an initial rate of 1,281 barrels per day. In August, the company brought the RU-1A sidetrack online at an initial production rate of 700 barrels per day. The company also sidetracked the RU-5 well toward the end of 2013.

Since then, Cook Inlet Energy has performed additional work on RU-7, adding perforations in the producing interval and conducting repairs to the platform and rig.

With the maintenance work underway, the company also began step-out drilling at the unit with RU-9, which the company said was “intended to capture oil reserves from a large four-way structure located approximately 2.5 miles southwest of the Osprey platform.” In September, after completing the well, Miller said that a well test confirmed the presence of oil: “While flow rates have varied preliminary results are encouraging.”

Through July 2015, the unit had produced nearly 3.5 million barrels of oil.

Scaled back plans

While earlier projections for Redoubt had envisioned a busy year, the decline in oil prices forced Cook Inlet Energy to scale back its ambitions. As with the West McArthur River unit, the company planned to drill as many as four sidetracks at the Redoubt unit to improve production from various fault blocks, according to the most recent plan of development.

The plan prioritized a sidetrack of RU No. 7A. The company would complete the sidetrack with hydraulic fracturing, which executives believe would double or triple recovery rates, according to recent company statements. Given the uncertainty of oil prices and the attractiveness of gas developments in the portfolio, the company has said it would wait until summer before deciding whether to sanction the sidetrack this year.

The sidetrack will likely be the only well at Redoubt this year, according to the company, and the results will determine whether and how the company proceeds in the near term.

The proposed plan of development calls for drilling as many as two other sidetracks starting in April 2017. The RU No. 3A and RU No. 3B sidetracks would target the Central fault block to produce oil in the Hemlock participating area. The company had originally planned to sidetrack the existing RU No. 3 well or RU No. 4A sidetrack (both of which have been depleted) last year but delayed those plans in favor of sidetracking RU No. 7.

The plan also proposes an RU No. 7B sidetrack for the near term. The Alaska Oil and Gas Conservation Commission issued a drilling permit for RU No. 7B in March 2015.

Cook Inlet Energy has identified two other oil-bearing fault blocks at the unit, although plans for delineating those Northern and Southern blocks are vague and dependent on economics, according to the company, which hopes to start drilling by April 2017.

Work on the Southern block depends on the results of the RU No. 9 well. The company plans to conduct rigged maintenance to change out a pump on the well in the near term.

The company recently described the November 2014 well as a disappointment, saying that it only produced about 100 barrels of oil per day before an electrical failure.

The North Fork unit

Standard Oil of California drilled the North Fork 41-35 discovery well in 1965 while looking for oil but relatively cheap natural gas prices made development uneconomic.

Renewed interest in the onshore field in the southern Kenai Peninsula began in the late 1990s but each new company that acquired the field failed to bring it into development.

In 2007, the Denver independent Armstrong Oil and Gas Inc. acquired the prospect from Gas-Pro LLC and brought on four partners, all small independents. The joint venture re-entered the original well, drilled new wells and brought the unit into production in 2011.

Through its subsidiary Cook Inlet Energy, Miller Energy Resources Ltd. acquired the North Fork unit in late 2013. The decline in global oil prices in late 2014 made the existing gas production at the North Fork unit particularly valuable to the company.

With North Fork, Miller acquired six wells and 15,465 acres, the transmission subsidiary Anchor Point Energy LLC and the existing supply contract with Enstar Natural Gas Co.

After completing the acquisition in February 2014, Cook Inlet Energy became operator of the onshore unit in the southern Kenai Peninsula and filed an updated development plan.

Through July 2015, North Fork had production 11 billion cubic feet of natural gas.

Up for sale?

When Cook Inlet Energy acquired North Fork, the company proposed a drilling program for fiscal year 2015 that included working over the existing NFU 14-25 and NFU 32-35 wells, sidetracking the existing NFU 23-25 well and drilling the new NFU-07 and NFU 32-35 wells to increase gas production. Looking down the road, a proposed fiscal year 2016 program called for drilling three new gas wells: NFU-08, NFU-09 and NFU-10.

But the company was also thinking long term, and said that it saw an opportunity to drill as many as 24 wells at the unit. The drilling would attempt to expand gas production as well as start oil production, which had stymied previous operators, including Armstrong.

In a 50th plan of development for the field, submitted to the state in late December 2014, Cook Inlet Energy said it had spent the year analyzing existing seismic and well data and planning an appropriate drilling program. The company said it intended to drill three wells - NFU No. 24-26, NFU No. 42-35 and NFU No. 31-3 - from the existing North Fork pad using the recently purchased Glacier Rig 1, which is now known as Rig 37.

By March 2015, the company had completed the NFU No. 24-26 and NFU No. 42-35 on time and on budget and was preparing to drill three workovers planned for the unit. As of late July 2015, the NFU No. 24-26 was producing some 1.8 million cubic feet per day and NFU No. 42-35 was producing some 300,000 cubic feet per day, according to Miller.

“After conducting a detailed field study, we continue to believe North Fork holds significant recoverable gas and that we can drill additional North Fork wells even more cost and time efficiently, as well as more productively,” Miller Energy CEO Carl Giesler said in a quarterly teleconference with analysts and investors at the end of July 2015.

The company also said it had identified seven projects at North Fork that would increase production by an estimated 1.5 million cubic feet per day and could start oil production.

For the current plan of development, which runs through March 2016, Miller said it intended to continue the delineation program while also analyzing results with an eye toward a potential drilling program outside the North Fork Gas Pool No. 1 participating area. Lower risk gas targets at North Fork are a major focus for Miller in 2015, given the attractiveness of gas compared to oil in the current commodity price environment.

Whether Cook Inlet Energy will have the opportunity to pursue those projects is unclear, both because of financial and regulatory uncertainty and because Miller recently listed the North Fork unit and the associated Anchor Point pipeline as potential sales options.

The Badami unit

Conoco Inc. discovered the Badami oil pool in 1990 and BP Exploration (Alaska) Inc. brought the eastern North Slope oil field into production in August 1998.

From nearly the beginning, the complex geology of the region hampered operations.

Oil production peaked a month after startup at some 7,450 barrels per day. By January 1999, it had fallen to some 3,300 bpd. BP suspended production until May 1999 to upgrade facilities. By July, the field was producing nearly 5,300 bpd. Production had fallen to some 3,000 bpd by the end of the year and 1,300 bpd by July 2003, when BP suspended operations for more than two years, until September 2005. Production was averaging 1,785 bpd by October, 1,437 bpd by December 2005 and some 876 bpd by August 2007, when BP suspended operations to allow reservoir pressure to recharge.

In mid-2008, BP took a different approach. The company gave Savant Alaska and ASRC Exploration LLC a stake in Badami in return for returning the unit to operation. With Savant taking the lead, the companies succeeded in returning the unit to sustained production, albeit at low levels. The two companies acquired the field outright in early 2012 and acquired the Badami Pipeline system through a joint venture in early 2014.

Miller Energy Resources Ltd. acquired Savant Alaska in May 2014 and closed on the purchase in December 2014, becoming operator and majority owner of the unit. As the deal was moving toward closing, global oil prices fell by more than half, which severely challenged the economics of an already complex operating environment. Savant, and then Miller, decided to defer much of the development plan outlined for 2014 and early 2015.

Through July 2015, Badami had produced some 7.2 million barrels of oil.

Future uncertain

The current plan of development at Badami calls for completing those projects, although the realities of the global oil market have created uncertainty for the unit going forward.

In its 11th plan of development, from Nov. 16, 2014, through July 15, 2015, Savant had planned to evaluate hydraulic fracture stimulations on the Bl-18A and Bl-38 wells and to use those results to design stimulations for wells to be drilled in the first half of this year.

Ultimately, the company postponed the completion activities for Bl-18A and Bl-38 because it was unable to secure the necessary equipment and barge it to the Badami unit in time to complete the activities. The company also postponed the wells planned for earlier this year because of a similar problem with securing equipment, a desire to conduct a geological review as part of the change in ownership and current oil prices.

The 12th plan of development, through July 15, 2016, calls for completing hydraulic fracturing operations on the two wells and, if prices permit, drilling the two new wells.

Over the course of 2015, Miller regularly mentioned Badami as one of the Alaska assets it would be willing to sell in order to improve its financial position as a company.

The East Mikkelsen prospect

Another outstanding factor that could complicate those plans is the fate of five leases currently under appeal. The leases are between Badami and the Point Thomson unit.

In late 2012, Savant and the Alaska Venture Capital Group LLC asked the state to add seven leases, covering some 10,121 acres, to the Badami unit. The addition would have incorporated the East Mikkelsen prospect into the unit. Instead, in March 2013, the Alaska Department of Natural Resources agreed to include only two of the seven leases.

The ruling also approved an exploration plan that required Savant to drill a directional well through the entire Canning Formation and into the underlying Hue Shale to evaluate the potential of the hydrocarbon-bearing Killian interval encountered in the earlier East Mikkelsen Bay No. 1 well. If successful, Savant would have needed to complete the well, perform an extended test and present the results of the test to the state by June 30, 2014.

Savant appealed the ruling in April 2013, saying it needed all seven leases to effectively explore the prospect. To address the pending drilling deadline, Savant also requested a stay of its plan of exploration in August 2013. Even though the company and state officials have met in the years since filing the appeal, the matter remains unresolved.

In the current plan of development, Miller said it would review all potential targets outside the participating area, “including, but not limited to, the Killian Sands on the east side of the unit” and “intends to continue exploration to fully explore the unit area as economic conditions warrant, and once the unit expansion appeal issue is resolved.”

Without definite plans for the acreage, though, and with the appeal unresolved, the Badami unit “remains subject to a finding of default,” according to the state.



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