ExxonMobil Production Co. has successfully drilled and cased PTU-15, the first development well for the Point Thomson project on Alaska's North Slope. In addition, a 60-mile ice road has been completed from Endicott to Point Thomson which enables the transport of heavy equipment and materials to the site.
ExxonMobil drilled the well to a measured depth of over 16,000 feet. The shore-based rig directionally drilled under the Beaufort Sea to the targeted gas reservoir more than 1.5 miles offshore.
ExxonMobil senior project manager Lee Bruce added, "PTU-15 pushed the limits of drilling technology and demonstrated that the Point Thomson drilling plan is sound."
The rig will be moved to the second development well at Point Thompson (PTU-16) and continue drilling. Work continues on front-end engineering and design for the initial production system.
"We are continuing to progress the Point Thomson project work. We are ready to resolve all outstanding issues with the Department of Natural Resources to maintain the pace and momentum set by the more than 1,500 people and 150 companies that worked on the project over the past year," added Pittman.
In January, a judge rejected the Department of Natural Resources' decision to terminate Exxon's leases in the project. The Department believes the company has had adequate time to drill and develop the leasehold, but Exxon argues that harsh conditions and the remote location call for leniency in timing. The company first signed the lease agreement in 1977, and five years ago, the Department decided that was long enough.
The recent ruling overturning the Department's decision states Exxon was not given its constitutional right to due process.
Exxon and its Point Thomson partners–BP, Chevron, and ConocoPhillips–have launched a $1.3 billion effort to start production of at least 10,000 barrels a day from the project by 2014.
Photo courtesy of ExxonMobil
The Point Thomson project, located roughly 60 miles east of Prudhoe Bay on Alaska's North Slope, is scheduled to commence production in 2014. Field development will include a gas cycling plant designed to produce hydrocarbon liquids and re-inject natural gas back into the reservoir, making Point Thomson the highest-pressure gas cycling operation in the world.
The remote natural gas and condensate field holds an estimated 8 trillion cubic feet of gas–about 25% of the North Slope's gas resources–and about 200 million barrels of condensate.
Anadarko Lucius appraisal well encounters over 600 net feet of pay
In Keathley Canyon block 875 in the deepwater Gulf of Mexico, Anadarko Petroleum Corp. has encountered almost 600 net feet of oil pay with the Lucius sidetrack appraisal well. The find is considered high quality with additional gas-condensate pay in thick subsalt Pliocene and Miocene sands.
"The successful Lucius appraisal well confirms this is a major discovery with substantial resource potential," said Bob Daniels, Anadarko senior vice president, Worldwide Exploration. "The reservoirs are characterized by excellent porosity and permeability and contain high-quality oil. We anticipate additional appraisal activity in 2010 as we continue to evaluate development options for this very large accumulation."
The Lucius appraisal well was drilled as an up-dip sidetrack, approximately 3,200 feet due south of the discovery well. It was drilled to a total depth of approximately 20,600 feet in approximately 7,100 feet of water. The Lucius discovery well, announced last month, was drilled to a total depth of about 20,000 feet and encountered more than 200 net feet of pay.
Anadarko operates the Lucius well with a 50% working interest. Co-owners include Plains Exploration & Production Co. with a 33.33% working interest and Mariner Energy Inc. with 16.67% working interest.
Once operations are complete at the Lucius appraisal well, Anadarko plans to move the rig to drill an appraisal of Anadarko's subsalt Miocene Heidelberg discovery in the Green Canyon area of the Gulf of Mexico.
WoodMac analysis
Implications
- It is likely large enough to merit full-scale, standalone development.
- The announced net pay of 600 feet is very significant, and is larger than the 500 feet encountered at Cascade, a Paleogene (Lower Tertiary) field currently being developed. Moreover, the reservoir quality appears to be better than that of the Paleogene reservoirs.
- Existing technology could be used, in contrast to the Paleogene discoveries, which require advances in completion technology.
Development
- Because the formations are shallow, the wells should be reasonably fast, and therefore relatively low-cost, to drill.
- Well was drilled in less than 2 months and reached 20,000 feet – much faster than Paleogene wells in the area, which can take several months.
Geology
- WoodMac's initial estimate for recoverable reserves is about 150 – 200 MMbbls of liquids/oil and around 1 Tcf gas.
- Lucius lies 7.5 miles east of Chevron's 2009 Paleogene Buckskin discovery.
- Good reservoir quality means potentially better economics than the Paleogene discoveries - thick reservoir sands with high porosity and permeability
GE Energy partners with Marlin, Sequel to acquire reserves for $200M
GE Energy Financial Services, a unit of GE, has formed partnerships to acquire West Texas natural gas and North Dakota oil and gas reserves for a total of nearly $200 million.
In the first transaction, GE Energy Financial Services formed a partnership with independent oil and gas company Marlin Energy LLC. Their new alliance, Marlin Permian LP, acquired natural gas reserves in West Texas from an undisclosed seller for $65 million. GE Energy Financial Services will serve as limited partner. Lafayette, La.-based Marlin Energy will serve as both general partner of the partnership and operator of the assets.
In the second transaction, GE Energy Financial Services has formed a partnership with Denver-based Sequel Energy LLC to acquire oil and gas reserves in the Williston Basin of North Dakota from Denver-based St. Mary Land & Exploration Co. for $137 million.
As part of its turnaround program, St. Mary Land & Exploration Co. entered into two agreements to sell non-core properties in the Rocky Mountain region with estimates of 20 MMboe of proved reserves and 3,000 boe/d of production.
In December, St. Mary entered into an agreement with Legacy Reserves Operating LP to sell the Wyoming portion of the divestiture package for $130 million. This recent agreement with GE Energy Financial Services and Sequel Energy was negotiated in January.
In this transaction, GE Energy Financial Services will serve as the limited partner, with Sequel serving as general partner and operator. The acquisition fits well in to privately-held Sequel's strategy to acquire assets in domestic onshore areas with long-lived, multi-pay production at moderate depth and which possess manageable reserve risk.
— Mikaila Adams
Contango revenues, net income up,$72.5M earmarked for GoM exploration
Contango Oil & Gas Co. reported revenues from sales of natural gas, oil and natural gas liquids for the three months ended December 31, 2009 of roughly $46.1 million. The number is up from the $45.5 million reported for the same period last year. Net income attributable to common stock for the same three-month period was $19.1 million–an increase from the reported $18.9 million during the same three months in 2008.
For the remainder of calendar year 2010, Contango's capital expenditure budget calls for an investment of nearly $72.5 million to drill up to six offshore wells in the Gulf of Mexico, $14 million to complete, build a platform, lay a pipeline, build facilities and bring its Nautilus discovery to production, $19.2 million to continue drilling onshore wells in Panola County, Texas under its joint venture with Patara Oil & Gas LLC, $3 million to drill up to two conventional onshore Texas prospects, and $1.5 million to plug and abandon Grand Isle 72.
Production is currently estimated at 85 million cubic feet equivalent per day, net to Contango. As of February 9, 2010, the company had no debt and roughly $75 million in net cash and cash equivalents.
Kenneth R. Peak, the company's chairman and CEO said, "We expect to be very busy the rest of this year and may have three Gulf of Mexico wells drilling in March 2010. Our Dude prospect (Matagorda Island 617) should spud in February 2010 with two more GOM wells scheduled to spud in the March-April 2010 time frame.
Concerning natural gas prices, the weather is cooperating on the demand side, but natural gas supply continues to hold steady. I wouldn't be surprised by either $3.00 or $6.00 natural gas over the next year or so, but we have good prospects and are aggressively moving forward to drill."
On heels of Triad Energy acquisition, Magnum Hunter sets $25M 2010 budget
Magnum Hunter Resources Corp. has approved an initial 2010 capital budget of $25 million. Most of the budget, $17 million (70%), is set for exploration and development activities associated with the company's recently-closed acquisition Triad Energy Corp. assets.
In late October, Houston-based Magnum Hunter entered an agreement with privately-held Triad Energy Corp. to acquire substantially all of Triad's oil and gas exploration and production operating assets under a plan of reorganization. The $81 million transaction includes Triad's oil and gas property interests in roughly 2,000 operated wells, a natural gas pipeline, salt water disposal facilities, three drilling rigs, workover rigs and other oilfield equipment located in Kentucky, Ohio, and West Virginia. Additionally, Magnum Hunter acquired roughly 50,000 net mineral acres in the Marcellus Shale play. Magnum Hunter will pay cash, refinance Triad's senior debt, and issue convertible preferred stock at closing.
As of June 30 2009, Ohio-based Triad had total proved reserves of 5.2 MMboe (69% crude oil and 29% proved developed), and daily production of 1 Mboe from 2,000 wells.
The company expects to fund the newly-set 2010 budget, which does not include expenditures for possible merger and acquisition activities, with internally generated cash flows from operating activities and cash liquidity under its $150 million revolving commercial bank line of credit ($70 million borrowing base).
The company's plans for the Triad assets include the horizontal drilling of a minimum of two unbooked Marcellus Shale locations in Tyler County, West Virginia. The company plans to spend roughly $9 million on upgrading and completing the Eureka Pipeline system in West Virginia, also part of the Triad transaction.
For the Eagle Ford Shale, Magnum Hunter has earmarked roughly $7 million (28%). The company plans to horizontally drill two unbooked Eagle Ford Shale locations during fiscal year 2010, with one of these to be completed before mid-year. The company will be fracing this month an Eagle Ford Shale vertical well to test the fracturing and stimulation process for use on the company's Eagle Ford Shale mineral lease acreage inventory. The balance of Magnum Hunter's capex budget in the Eagle Ford Shale will be for additional leasing related activities that are currently ongoing.
Callon enters Haynesville, earmarks majority of 2010 CAPEX to onshore
With its shift to diversify its asset base to onshore properties with growth in mind, Natchez, Miss.-based Callon Petroleum Co. has earmarked most of its 2010 budget to both its Permian, and newly-acquired Haynesville interests.
Marking its first acquisition in the North Louisiana Haynesville Shale play, the company paid $3 million for a 70% operating interest in a 577-acre Haynesville unit in Bossier Parish. The company plans to drill and complete two horizontal wells in 2010, the first planned to spud by summer. The Unit will be developed with up to seven horizontal wells. The company estimates the gross ultimate gas recovery to be 6.4 billion cubic feet of natural gas per well at an estimated cost of $9.0 million to drill and complete. Of the company's proposed 2010 budget of $61.7 million, $14.5 million (24%) is expected to be spent on shale gas development.
The company plans to begin drilling in the Permian play shortly, with a goal of up to 16 Wolfberry wells in 2010. The company has set aside $20 million (33%) of its 2010 budget for Permian operations.
"We've been working on this strategy shift over the past 18 months, developing the plan, working to find the right assets and building the right team to set the foundation for our plan to diversify our asset base," Fred Callon, chairman and CEO points out. "The cash flow generated from our two deepwater fields with quality, long-lived reserves will be reinvested into onshore conventional oil and shale gas properties."
Earlier in February, the company announced a $100 million credit agreement signed with Regions Bank. The facility will have an initial borrowing base of $20 million and replaces the company's existing credit agreement. Borrowings, if needed, will be used for capital expenditures and general corporate purposes.
Callon's hedging strategy is to employ hedges as a tool for mitigating price-related risk for up to 50% of its annual production. Currently, the company has approximately 15% of its natural gas hedged in the form of costless collars with an average floor of $5.00 and an average ceiling of $8.30.
— Mikaila Adams
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