Miller Energy Resources Ltd. was bullish about Alaska when it arrived in the state in 2009, but the Tennessee-based independent became far more bullish over this past year.
The Tennessee independent is the parent company of Cook Inlet Energy, which operates a series of fields and facilities on the west side of Cook Inlet and several exploration licenses and leases in the Susitna basin. Toward the end of 2013, Cook Inlet Energy acquired the North Fork unit from Armstrong Cook Inlet LLC for nearly $65 million.
Then, in May 2014, Miller acquired Savant Alaska LLC for some $9 million. The small Alaska independent Savant operates the Badami unit on the eastern North Slope. Miller had initially said it hoped to close the deal by August 2014 but later pushed the deadline to November 2014 and then to December 2014, after The Producers went to print.
And in September 2014, Miller signed a non-binding letter of intent to buy the Alaska assets of Buccaneer Energy Ltd., which filed for bankruptcy protection earlier in the year. That proposition also reached its resolution after The Producers went to print. (For more information about those assets, see the profile on Buccaneer Energy Ltd.)
If completed, the acquisitions would make tiny Miller Energy and its subsidiaries one of only three companies - alongside ConocoPhillips and Hilcorp (whose North Slope deal is also pending) - to operate production on both of Alaska’s major basins. As it stands, the opportunities in Alaska have convinced Miller to sell its remaining Tennessee assets.
“While we still believe Tennessee has significant growth potential, our capital is clearly better allocated to our Alaskan operations and the investment opportunities that exist there,” former Chief Executive Officer Scott Boruff said in a statement in June 2014.
In August 2014, a third party report from Ryder Scott Co. estimated that Miller had 11.7 million barrels of proved developed and undeveloped oil reserves at its Alaska properties, up from a previous estimate of 10.5 million barrels. Currently, Miller is producing some 2,500 net barrels of oil equivalent per day from the West McArthur River and Redoubt units and some 7.4 million net cubic feet of natural gas per day from the North Fork unit, with an estimated 600 net barrels of oil equivalent per day from the Badami unit.
As of September 2014, Cook Inlet Energy owned some 300,388 acres of state leases, which does not include approximately 25,000 acres of state leases owned by Savant.
In September 2014, Miller Energy announced that Carl F. Giesler Jr. would take over as chief executive officer of the company, a position previously held by Scott Boruff.
While Miller currently operates production in Cook Inlet, the company is primarily funding its expansive drilling program through several large credit facilities. The company has noted that its cost of capital has decreased over the past three years.
Pacific Assets: WMRU
Through Cook Inlet Energy, Miller arrived in Alaska in late 2009 when it acquired several Pacific Energy Resources Ltd. assets for $2.25 million in bankruptcy proceedings.
The assets included the West McArthur River unit and oil field, the West Foreland gas field and the Redoubt unit with its associated Osprey platform and Kustatan facility, as well as a stake in the Three Mile Creek unit and a portfolio of exploration prospects.
Miller Energy now collectively calls those properties its “Pacific Assets.”
When Cook Inlet Energy acquired the properties, the company presented a strategy of repairing existing wells in the short term and drilling new wells over the long-term.
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.
In July 2010, Cook Inlet Energy returned the shut-in Kustatan field KF-1 well to production at 70,000 cubic feet per day, which the company used for fuel operations.
Those maintenance initiatives significantly increased oil production at West McArthur River, but Cook Inlet Energy aspired to drill as many as five new wells at the unit, which the company said would have the potential to increase production by some 2,000 bpd.
Cook Inlet Energy has drilled two wells at the unit this year.
The 15,535-foot WMRU-8 well 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 measured depth WMRU-2B sidetrack from the non-producing WMRU-2A wellbore came online in June 2014 at an initial rate of 630 barrels of oil equivalent per day, which was “substantially above what we originally anticipated,” Hall said.
Cook Inlet Energy is also expanding West McArthur River through exploration work.
Over the latter half of 2013, Cook Inlet Energy drilled the 18,475-foot Sword No. 1 exploration well directionally from land near the unit to a bottom-hole target beneath the inlet. Between November 2013 and June 2014, the well had produced some 116,000 barrels of oil, according to the company. The Alaska Oil and Gas Conservation Commission allowed the company to comingle production from three zones, which the company said would increase flow rates and thus improve the economics of the well.
The results have prompted the company to plan a Sword No. 2 well.
This fall, Cook Inlet Energy hopes to repeat its success with Sword by exploring the nearby Sabre prospect from the existing West McArthur River unit pad. The company sees the potential for a follow up next year and a six-well development program.
Miller wants to drill a second Sabre well this fiscal year and three more next year. As of September, Miller was “evaluating joint venture offers for participation in the project.”
A $35 million program (after credits) for fiscal year 2015 includes the Sabre No. 1 well, a WF-3 well at West Foreland and a sidetrack of the WMRU-8 well drilled this year.
Pacific Assets: Redoubt
The Redoubt unit and its associated Osprey platform were offline in 2009.
Cook Inlet Energy brought the platform online in mid-2011 by replacing electric submersible pumps in the RU-1 and RU-7 wells, which allowed the wells to flow at 350 boe per day and 250 boe per day respectively. The company later shut-in RU-1 because of an equipment problem, but the RU-7 well continued to produce some 230 boe per day.
As with West McArthur River, Cook Inlet Energy launched a program to repair existing wells and drill new wells. The company announced plans to drill four sidetracks off existing damaged wells, which it expected would produce some 2,000 bpd. The company also saw the possibility to drill 13 new wells from the platform, with proper investment.
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.
Last summer, in June 2013, Cook Inlet Energy more than doubled its total Alaska crude output by bringing the RU-2A sidetrack online at an initial production rate of 1,281 barrels per day. In August, the company brought the RU-1A sidetrack online at an initial production rate of 700 bpd. The company also sidetracked the RU-5 well later that year.
Since then, Cook Inlet Energy performed additional work on RU-7, which added perforations in the producing interval and conducting repairs to the platform and rig.
With the maintenance work under way, 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.”
The remaining inventory for fiscal year 2015 - a $75 million program (after credits) - calls for drilling the RU-12 to target a northern block and sidetracking RU-3 and RU-4.
The company is also considering four additional wells at the Redoubt unit in fiscal year 2016: RU-8, RU-13, RU-14 and RU-15, all of which would test additional oil targets.
The wells are targeting four new fault blocks. A series of “positive” drill stem tests from the 1960s confirmed the north and south blocks, RU-1 tested the central fault in 2001 at an initial rate of 1,089 barrels per day and RU-2 tested the central fault in 2002 at an initial rate of 1,954 barrels per day, according to the company. Cook Inlet Energy believes the step-out program could “significantly increase proved reserves.”
Trans-Foreland Pipeline
As an oil producer on the west side of Cook Inlet, Miller is well aware of its distance from local markets and also its proximity to the Redoubt volcano, which shut down oil production and distribution for months with a series of eruptions in 2009. That’s why, in 2012, the company began toying with the idea of a pipeline across the Cook Inlet.
The idea was a $53 million subsea Trans-Foreland Pipeline to carry oil from the Kustatan production facility to the existing Tesoro oil refinery in Kenai. A 29-mile pipeline would eliminate the short tanker voyage currently used to move oil across Cook Inlet.
After agreeing to fund some early design work, Tesoro took over the project in late October 2013 by forming the wholly owned subsidiary Trans-Foreland Pipeline Co. LLC.
A deal gave Tesoro sole rights to pursue the project through the end of 2015, at which point Cook Inlet Energy would have the option to reacquire its interest for a set sum.
Construction is expected to begin next year.
North Fork
Standard Oil of California discovered the North Fork field in 1965 while searching for oil. But the value of gas and the distance from Anchorage made the field uneconomic.
A string of companies attempted to develop the field starting in the late 1990s, but none succeeded until a subsidiary of Armstrong Oil and Gas LLC acquired the property.
With four partners, Armstrong drilled the North Fork 34-26 well in June 2008.
“I am 100 percent positive we have a gas well - in any other part of the world that’s what I would say, but we still have to get a pipeline to it,” Armstrong Vice President of Land and Business Development Ed Kerr told Petroleum News in September 2008.
Kerr publically estimated that North Fork contained between 7.5 billion and 12.5 billion cubic feet of gas reserves, with the “realistic” possibility of reserves as high as 20 billion to 60 billion cubic feet. But Kerr also said that the company would need to negotiate a price between $7 and $10 per thousand cubic feet to make the prospect economic.
Enstar Natural Gas Co. agreed to favorable terms in return for drilling commitments.
In mid-2010, Armstrong re-entered the original NFU No. 41-35 well, drilled the 11,700-foot NFU No. 14-25 directional well and drilled the 12,070-foot NFU No. 32-35 directional well. Armstrong brought the North Fork unit online in late March 2011.
In late 2012 and early 2013, Armstrong drilled the NFU No. 22-35 and NFU No. 23-25 wells. Under a 48th Plan of Development in place for 2013, Armstrong tested NFU No. 23-25 and NFU No. 22-35 and continued to monitor its existing production wells.
With North Fork, Cook Inlet Energy acquired six wells and 15,465 acres, the associated transmission subsidiary Anchor Point Energy LLC and the existing contract with Enstar.
Since the sale closed, in February 2014, Miller Energy acquired the Glacier No. 1 drilling rig (now called Rig 37) for some $7 million and dispatched the carrier-mounted land rig to North Fork. With existing wells “currently choked back,” the company said that it was able to immediately increase production in the short-term. The 7.4 million cubic feet per day of net gas production in late August 2014 did not count supplies used from fuel gas.
While Cook Inlet Energy has already performed some early well work at North Fork, the company intends to pursue a more robust program starting this winter. In June 2014, the company said it was planning to work over two existing wells and drill two new wells.
Actual workloads depend on various factors, but Cook Inlet Energy’s inventory for fiscal year 2015 calls for 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 target additional gas production from the field. The drilling inventory for fiscal year 2016 calls for drilling three new natural gas wells: NFU-08, NFU-09 and NFU-10.
The current year program is expected to cost some $15 million, after credits.
The long-term plans are more intriguing.
At the time of the sale, Cook Inlet Energy said it saw the potential to drill as many as 24 additional wells at the unit. While many of those would expand gas production at North Fork, the company also sees the potential for oil development and claims to have had “encouraging preliminary results” from an evaluation of the oil potential in the deeper Hemlock formation at the field, conducted while working over an existing gas well.
The original NFU No. 41-35 well tested minor amounts of oil in the Hemlock but not enough to convince Socal to develop the reservoir. Armstrong came up empty-handed when it extended one of its natural gas wells to test the oil potential of the Hemlock.
Badami history
The Badami unit has long been one of the most intriguing fields on the North Slope.
Conoco Inc. discovered the Badami oil pool in 1990 with the Badami No. 1 well. BP Exploration (Alaska) Inc. brought the field online in August 1998. But oil production peaked a month later at 7,450 barrels per day. By January 1999, production had fallen to 3,300 bpd and BP shut-in the field through May 1999 to upgrade facilities. The field produced nearly 5,300 bpd in July 1999 but production was down to 3,000 bpd by the end of the year and 1,300 bpd by July 2003, when BP suspended operations for two years.
BP restarted the field September 2005 and production was averaging 1,785 bpd by October. But production fell to 1,437 bpd by December 2005 and some 876 bpd by August 2007, when BP again suspended operations to allow the field to recharge.
The Colorado-based independent Savant Resources LLC came to Alaska in 2006 and drilled the Kupcake No. 1 exploration well from an ice island in Foggy Island Bay, some 20-miles west of Badami, in early 2008. The target interval in the Kemik formation “was thinner than anticipated” and the porous Cretaceous sandstone proved to be “water wet,” according to a partner on the program, but Savant gained crucial Arctic experience.
In mid-2008, local affiliate Savant Alaska and ASRC Exploration LLC agreed to take on the challenge of restarting Badami in return for a stake in the unit. In early 2012, after years of development work, the partners acquired the field outright and Savant became the newest and smallest operator on the North Slope. In early 2014, BP sold the Badami pipeline system to Nutaaq Pipeline LLC, a partnership of Savant and Arctic Slope Regional Corp.
Given its current status as the easternmost producing field on the North Slope, the Badami unit will provide a crucial link between the Point Thomson unit and the existing North Slope infrastructure once ExxonMobil brings the easterly field into production. Nutaaq Pipeline recently sought a rate increase on its pipelines to better cover costs.
The current program at Badami has been a combination of exploration, development and maintenance work, all of which Miller Energy said it intends to continue and expand.
In early 2010, Savant drilled two Badami penetrations.
The first was B1-18A, a sidetrack of the B1-18 well that BP drilled in 1998. Savant drilled the sidetrack to test whether horizontal drilling techniques could improve production rates from the notoriously complex geology at the field, a series of turbidite sandstones deposited in channels with minimal communication from one to another.
The second was B1-38, an exploration well into the Red Wolf prospect, an interval beneath the Brookian formation, where BP had previously focused development drilling.
The exploration well encountered oil in two horizons.
The first was the Kekiktuk formation, which also contains the oil reservoir for the nearby Endicott unit. In early 2012, Savant targeted the Kekiktuk again with the Red Wolf No. 2 exploration well. The target zone was wet, though, and Savant suspended its pursuit of Red Wolf and transferred the deep zones at those leases to a consortium of independents.
The second horizon was in the shallower late Cretaceous Killian sands, which Savant used to restart sustained oil production from the Badami unit in November 2010.
Work since has been primarily maintenance.
Using a conventional rig and an electric submersible pump, Savant added some 54,259 barrels of oil production from the B1-16 well between May 2012 and March 2013. The oil “would not have otherwise been produced” without the work, the company said.
Savant also restored integrity to the B1-28 well by repairing a tubing leak and said that it was planning additional repairs intended to bring the well back into regular production.
The current plan of development for Badami, active through November 2014, also called for Savant to hydraulically fracture the B1-18A sidetrack and the B1-38 well. The work at B1-18A would gauge the economics of hydraulic fracturing at horizontal wells in the Brookian formation at Badami. The work at B1-38 would do the same for the deeper Killian sands, while also gauging the size of the reservoir. The information would underpin an application for a participating area for the Killian sands, Savant has said.
Savant reported oil production averaging some 1,020 bpd through the first six months of 2011 and subsequently topping 1,300 bpd by July 2013. But production is currently around 1,100 bpd from eight wells, according to Miller Energy and AOGCC figures.
Miller’s plans
When it acquired Savant, Miller Energy said it intended to “significantly enhance the value” of the assets it was acquiring - both producing assets and exploration properties.
The sale would give Miller a 67.5 percent interest in the Badami unit, 100 percent interest in surrounding exploration leases and a stake in the various Badami unit infrastructures.
“The acquisition of Savant will significantly expand Miller Energy’s Alaskan asset ownership, complementing our existing Cook Inlet operations and providing us with additional wellbore diversification,” Boruff said at the time. “This transaction increases our profile in the Alaskan oil and gas community, and gives us a credible foothold in the world-class North Slope resource play, including existing production, a developmental runway and substantial mid-stream assets. By utilizing our combined team’s expertise and experience, we expect to significantly enhance the value of these assets. This transaction is another example of our ability to identify and acquire assets with substantial upside that Miller can unlock, providing a clear path to increased shareholder value.”
Miller’s initial plans call for sidetracking the existing B1-14 and B1-28 wells at the unit, at a cost of some $15 million each, according to Miller. The company has estimated that the two wells contain some 2 million barrels of recoverable oil reserves between them.
The fiscal year 2015 program is estimated at $25 million after credits.
