ConocoPhillips, PetroChina team up for unconventional natural gas exploration
Houston-based oil and gas giant ConocoPhillips (NYSE: COP) has teamed up with China's largest oil and gas producer, PetroChina Company Ltd. (PetroChina) on agreements targeting the unconventional resource space in Western Australia and in China's Sichuan Basin.
"ConocoPhillips is pleased that PetroChina has recognized the significant resource potential and value of the Australian opportunities. Likewise, ConocoPhillips recognizes the Sichuan Basin as having some of the most prospective marine shales in China and looks forward to working with one of the world's leading energy companies," said Don Wallette, executive vice president, Commercial, Business Development and Corporate Planning, ConocoPhillips.
Australia
From ConocoPhillips, PetroChina will acquire a 20% working interest in the Poseidon offshore discovery in the Browse Basin, and a 29% working interest in the Goldwyer Shale in the onshore Canning Basin.
The Goldwyer Shale runs along the northern edge of Great Sandy Desert and stretches across 45,000 sq km of the onshore basin. It has generated particular interest since ConocoPhillips earned a 75% interest from New Standard Energy in July 2011 in exchange for $A113.5 million in drilling, coring and evaluation costs.
According to an April 2011 report by the US Energy Information Administration, the Goldwyer Shale contained 764 trillion cubic feet (tcf) of risked gas in place and 229 tcf of risked recoverable gas, the largest estimate for any basin in Australia.
China
ConocoPhillips also has agreed to enter into a Joint Study Agreement to identify unconventional resource reserves in the Neijiang-Dazu Block in China's Sichuan Basin.
Under the JSA, ConocoPhillips and PetroChina will study the potential for unconventional resource development in the approximately 500,000 acre Neijiang-Dazu Shale Block in the Sichuan Basin.
While China's geology is unlike North America's, some in the industry are cautiously optimistic that the gas trapped in difficult terrain in inland provinces like Shanxi and Sichuan is recoverable. The deep reservoirs carry with them low permeability and porosity, but the US has made great strides in the development of such reservoirs at home and the hope is that the technology will be effective in China, as well.
If technically and commercially viable, the companies will advance development under a production sharing contract, which would be agreed upon during the study period.
All three agreements still require government and partner approvals.
—Mikaila Adams
Analysts: Mississippi Lime JV metrics a negative for Chesapeake Energy
On February 25, Chesapeake Energy Corp. (NYSE:CHK) announced the execution of an agreement with China-based Sinopec to sell a 50% undivided interest in 850,000 of its net oil and natural gas leasehold acres in the Mississippi Lime in northern Oklahoma for $1.02 billion.
For its 425,000 net acres in the liquids-rich play, Sinopec will pay $1.02 billion in cash, of which approximately 93% will be received upon closing with no drilling carries involved—a departure from many of the Oklahoma City-based company's prior joint venture agreements.
Production from these assets (including Mississippi Lime and other formations), net to Chesapeake's interest and prior to Sinopec's purchase, averaged approximately 34,000 barrels of oil equivalent per day in the 2012 fourth quarter and, as of December 31, 2012, there was approximately 140 million barrels of oil equivalent of net proved reserves associated with the assets. Of the 34,000 boe/d production from the Mississippi Lime, roughly 45% came from oil, 9% NGLs, and 46% natural gas.
Comp metrics
The deal metrics come in lower than recent comps, noted analysts at Global Hunter Securities (GHS) and Stifel.
On August 4, 2011 SandRidge Energy (SD) entered a JV with Korea-based Atinum Partners Co. in which Antrim earned a 13.2% working interest in 860,000 acres (roughly 113,000 net acres) for $500 million, which equates to roughly $4,425/acre. Not long after, SandRidge announced a second JV with Repsol YPF, for 363,636 net acres in and around the area for $1 billion, or $2,750/acre, noted GHS, who said that today's deal comes in lower than already depressed expectations.
"CHK essentially did this deal at the value of current production and reserves ($60K/flowing and $14.57/boe proved), receiving little to no credit for the 425,000 undeveloped acres it gave up to Sinopec as well. The last two SD JV's were done at much more attractive terms, netting $2,750/acre and $4,425/acre and excluding associated production. CHK was counting on the MS Lime sale to be one of its big ticket sale items in order to hit its divestiture goal of $5B-$7B in 2013 - this deal highlights that CHK still has a long road ahead."
The negative sale price assessment was echoed by analysts at Stifel who, in a note to investors after the announcement, said that "the transaction metrics are a slight negative if current production from the assets are not included and a clear negative if 50% of existing production is included in the sales price."
Following Chesapeake CEO and president Aubrey McClendon's retirement announcement, Stifel analysts noted the company would likely become more aggressive in its asset sales.
Today's announcement firms up Stifel's view that "with the new management team, the company will be hitting the bids on asset sales rather than holding on to assets if the bids are not close to the underlying value."
Despite the price, the sale does help the company move closer to a 1-year risked NAV ($29/sh), said Stifel analyst who noted that "as asset sales progress ($4-$7 billion planned for the year), the company should be able to close its gap towards its 1-year $29 NAV and we maintain our $25 target price."
As the operator of the project, Chesapeake will conduct all leasing, drilling, completion, operations and marketing activities for the joint venture.
Jefferies acted as financial advisor to Chesapeake Energy in its joint venture with Sinopec around the company's Mississippi Lime assets. This transaction represents the 3rd JV Jefferies has advised on involving a Chinese national oil and gas company (others included CHK's Eagle Ford and Niobrara JVs with CNOOC). The transaction is anticipated to be completed in the 2013 second quarter.
—Mikaila Adams
Eni estimates 75 tcf of natural gas potential at offshore Mozambique discovery
Italy's Eni has made a new natural gas discovery within the Mamba Complex, in Area 4, offshore Mozambique, at the Coral 3 delineation well, which is the eighth well drilled back to back in Area 4.
The new discovery confirms the potential of Area 4 operated by Eni at 75 trillion cubic feet (Tcf) of gas in place of which 27 Tcf exclusively located in Area 4.
Coral 3 was drilled in 2,035 meters of water and reached a total depth of 5,270 meters. The well is located approximately 5 kilometers south of Coral 1, 15 kilometers from Coral 2, and approximately 65 kilometers off the Cabo Delgado coast.
The well encountered 117 meters of gas pay in a high quality Eocene reservoir and adds at least 4tcf of gas in place to Area 4.
The discovery proved the existence of hydraulic communication with the same reservoir of Coral 1 and Coral 2 and confirms the large size of the Coral discovery that is now estimated to contain 13 tcf plus of Gas in Place wholly located in Area 4. According to the company, the Coral wells showed excellent deliverabilities during the production tests and each well is expected to deliver high flow rates in production configuration.
Eni plans to drill another delineation well, Mamba South 3, in order to assess the full potential of the Mamba Complex discoveries, before moving back to exploration drilling in the southern sector of Area 4.
Eni is the operator of Area 4 with a 70% participating interest. The other partners of the joint venture are Galp Energia (10%), KOGAS (10%) and ENH (10%, carried through the exploration phase).
Petrobras confirms new oil discovery in Santos Basin pre-salt
Petrobras has confirmed the presence of good quality oil (31 º API) in ultra deep waters in the Santos Basin pre-salt while drilling well 1-SPS-98 (1-BRSA-1063-SPS), informally known as Sagitário. This is the first well to be drilled in the BM-S-50 block and is located 194 kilometers off the coast of the state of São Paulo in 1,871 meters of water.
The concession where this well is being drilled is located west of the main discovery in the Santos Basin pre-salt (cluster blocks).
The oil was found in carbonate reservoirs 6,150 meters below the salt layer. The well is still being drilled up to a final depth of 6,950 meters to define the bottom of the oil reservoirs.
Petrobras is the consortium operator (60%) in partnership with BG E&P Brasil (20%) and Repsol Sinopec Brasil (20%).
Chevron conducts successful test well at St. Malo in Gulf of Mexico
Chevron Corp. conducted a successful production test on the St. Malo PS003 well in the prolific Lower Tertiary trend in the deepwater Gulf of Mexico. Oil flow rates, though limited by testing equipment constraints, exceeded 13,000 barrels of oil per day.
The test, in Walker Ridge Block 678, targeted Lower Tertiary sands more than 20,000 feet (6,096 meters) under the sea floor and was conducted during August and September 2012. This is the first development well in the St. Malo field, which is being jointly developed with the Jack field.
"The results of this production test further confirm the significance of the St. Malo field," said Gary Luquette, president, Chevron North America Exploration and Production Company. "The jointly developed Jack and St. Malo fields are expected to provide a major step-up in Chevron's production from 2014 and produce domestic energy for decades to come."
The Jack and St. Malo fields are located within 25 miles (40 km) of each other and are being jointly developed with a host floating production unit located between the two fields in 7,000 feet (2,134 m) of water, approximately 280 miles (450 km) south of New Orleans, Louisiana. The facility is planned to have a design capacity of 177,000 barrels of oil-equivalent per day to accommodate production from the Jack/St. Malo development, which is estimated at a maximum total daily rate of 94,000 barrels of oil-equivalent, plus production from third-party tiebacks. Total project costs for the initial phase of the development are estimated at $7.5 billion.
Chevron has a working interest of 51% in the St. Malo field. Other owners of the St. Malo field are Petrobras (25%), Statoil (21.5%), ExxonMobil (1.25%) and ENI (1.25%).
Senex begins frac stimulation in search of unconventional gas in Cooper Basin
Senex Energy Ltd., operator of the onshore PEL 115 permit, has commenced fracture stimulation operations exploring for unconventional gas in the Southern Cooper Basin.
Fracture stimulation operations have begun at Kingston Rule 1. Work over and zone perforation operations have also commenced at Hornet-1 in preparation for fracture stimulation to begin there next month.
Kingston Rule-1 is the second well in a fracing program that includes other Senex 100% owned wells, with both Kingston Rule-1 and Hornet-1 located in PEL 115. The fracture stimulation program over these wells will be completed over a two-month period, with flow testing to continue into the June quarter 2013.
Kingston Rule-1 was drilled by Senex in late 2012 and intersected a total of 53 metres of net gas pay, with 9 metres in the Epsilon Formation and 44 meters in the Patchawarra Formation tight gas sands. The well also intersected 150 meters of Murteree and Roseneath Shales. Mud logs confirmed the presence of liquids rich hydrocarbons throughout the Permian section. The well is located 15 kilometers southeast of Senex's 100% owned Skipton-1.
The multi-stage fracture stimulation of this well will target tight gas sands within the Patchawarra and Epsilon formations. To date, three of a total of six zones have been fracture stimulated with bridge plugs set between each zone. The forward operation will be to perforate and fracture stimulate the remaining three zones, drill out the bridge plugs and then flow the well to recover the frac fluid and test for gas flow from the well.
Hornet-1 was drilled by Victoria Petroleum in 2004 and intersected gas shows in the Epsilon Formation and 28 meters of net gas pay in the Patchawarra Formation. Two drill stem tests were conducted on this well and resulted in gas flowing to surface. The multi-stage fracture stimulation of this well will target additional tight gas sands within the Patchawarra Formation.
As Hornet-1 was a pre-existing well, a work over rig was brought to site to prepare the well for fracture stimulation and perforate the zones in advance of the frac equipment arriving onsite. All of the proposed six zones have now been perforated with the frac equipment to move to Hornet-1 after Talaq-1.
Pecan North -1 marks seventh consecutive offshore Ghana find for Hess
Hess Corp. has completed drilling of its seventh consecutive successful exploratory well on the Deepwater Tano/Cape Three Points block offshore Ghana, the company said Feb. 27. The Pecan North-1 well, located approximately seven miles northeast of the Pecan-1 well, encountered approximately 40 feet of net oil pay in Turonian aged reservoir.
The wells were drilled by the Stena Drillmax drillship in a range of water depths between 5,623 and 8,245 feet. Hess achieved outstanding drilling performance in terms of drilling time and cost per foot with gross costs averaging $40 million per well for the last three wells, including success case logging.
Based on the results of these wells and Hess' experience in Equatorial Guinea, where the geology is similar, the company plans to submit appraisal plans for the various discoveries to the Ghanaian Government for approval on or before June 2. In parallel, Hess has begun pre-development studies on the block.
Hess holds a 90% working interest in the block and is the operator. GNPC is a 10% equity interest partner and is carried through to the production phase of the license.
