General Interest Quick Takes
SEC approves reserves reporting requirements
The US Securities and Exchange Commission unanimously approved changes to its reporting requirements for oil and gas producers. The adjustments reflect technological improvements over the last 25 years, SEC said Dec. 29, 2008.
SEC said the renewed disclosure requirements include provisions that permit use of technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. They also allow producers to disclose probable and possible reserves, which contrasts with earlier rules that limited disclosures to proved reserves.
“These updated rules consider the significant changes that have taken place in the oil and gas industry since the adoption of the original reporting requirements more than 25 years ago,” said John W. White, director of the SEC’s corporate finance division.
The revised disclosure requirements also require producers to report the independence and qualifications of entities that evaluate or audit reserves, file reports when a third party is used to prepare estimates or audit reserves, and report reserves using an average price based on the prior 12 months instead of yearend prices, according to SEC.
The use of an average price for oil and gas will lead to more reliable comparisons of reserves among producers and mitigate distortion of estimates that can result from using a single pricing date, SEC said. The full text of the changes will be posted on the commission’s web site as soon as possible, the commission said.
“In the more than a quarter century since the SEC last reviewed its rules in this area, there have been significant changes in technology that have increasingly limited the usefulness of current disclosures to the market and investors. These updates to the SEC rules will help ensure more meaningful and comprehensive disclosure of information that, even though it does not appear on a company’s balance sheet, is of significance to investors in making informed investment decisions,” said SEC Chairman Christopher Cox.
DOE to resume SPR fill in wake of oil-price slump
The US Department of Energy plans to take advantage of the recent crude oil price decline and resume filling the Strategic Petroleum Reserve, it reported Jan. 2.
DOE said it issued a solicitation to buy about 12 million bbl of crude to replenish supplies that were sold following Hurricanes Katrina and Rita in 2005. Congress overwhelmingly passed a law ordering DOE to suspend SPR purchases in May after prices broke the $100/bbl barrier. The ban expired Dec. 31, 2008.
The energy department also said it plans to seek repayments from refiners for emergency oil it released from the SPR following Hurricanes Gustav and Ike in 2008, to deliver deferred royalty-in-kind oil, and to solicit new RIK deliveries this spring. The actions are required under the 2005 Energy Policy Act, it said.
Planned acquisitions during 2009 will bring the SPR back to its 727 million bbl storage capacity and provide the US with about 70 days of net import protection.
China, Indonesia sign energy agreements
Indonesia and China have signed eight energy-related agreements, valued at $3.13 billion, during the third Indonesia-China Energy Forum (ICEF) in Jakarta.
The first agreement extended an oil and gas contract for a development in the Madura Strait, East Java, operated by China National Offshore Oil Corp. and Canada’s Husky Energy Inc.
Indonesia’s upstream oil and gas regulator BPMigas signed the 20-year extension of the two companies’ contracts, which were due to expire in 2012.
ICEF also witnessed two agreements on coal mining, one on biodiesel plants, and four on electric power production projects.
The eight agreements, and amount of finance, include:
- Oil and gas contract extension in Madura Strait (BP Migas, CNOOC, and Husky Madura Ltd.; $642 million).
- Biodiesel development in Jambi and South Sumatra (PT Kurnia Selaras and China Development Bank; $255 million).
- Coal mining joint venture in Muara Enim (Bukit Asam and Huadian Corp.; $14.40 million).
- Coal mining cooperation in East Kalimantan (PT Budi Dharma Kencana and Lark Guangdong Power Resources Inc.; $350 million).
- Power plant financing in Pelabuhan Ratu (Exim Bank of China and PT PLN; $481.94 million).
- Power plant financing in Pacitan (Exim Bank of China and PT PLN; $293.23 million).
- Power plant construction in Cilacap (PLN, CNTIE, and Shanghai Electric; $605.29 million).
- Power purchase agreement for Muara Enim (PT PLN and PT GH EMM Indonesia; $330 million).
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Exploration & Development Quick TakesSaudi Arabia announces eight oil, gas finds
Saudi Arabia’s minister of petroleum and mineral resources Ali bin Ibrahim Al-Naimi reported Jan. 5 that the state-owned Saudi Aramco has discovered five more oil fields and three gas fields in the country’s Eastern Province.
Al-Naimi said four of the oil fields are on land and one is in the Persian Gulf. They include Jaouf-11, Ramthan-9, Nayashin-1, Jareed-101, and Khorsaniya-114. The minister named the three gas fields–all offshore–as Arabiya-1, Rabib-1, and Hisbah-16.
Ramthan-9 is 400 km northwest of Dhahran, Jareed-101 is 130 km north of Dhahran, Khorsaniya-114 is 138 km northwest of Dhahran, and the gas fields Rabib-1 and Hisbah-16 are 125-200 km northeast of Dhahran.
Al-Naimi released first test production results from three of the wells, saying that Jaouf-11, about 300 km northwest of Dhahran, is producing 2,551 b/d of oil and 33,980 cu m/day of associated gas; Nayashin-1, 60 km northwest of Ramthan, is producing 2,076 b/d of oil; and the Arabiya-1 gas discovery 185 km northeast of Dhahran is producing 1.16 million cu m/day, he said.
Pemex to drill deep in Bay of Campeche
Pemex Exploration & Production is drilling its first deepwater well, Catamat-1, off Tuxpan, Veracruz state, using the Noble Max Smith semisubmersible. The wellsite lies in 1,200 m of water. The rig will take 150 days to drill to 5,200 m.
The rig will be serviced by seven supply vessels and two helicopters from the marine terminal at Cobos, 400 km from Veracruz. Pemex improved an access road to Cobos and began upgrading port facilities in April 2008 to accommodate the drilling.
The governor of Veracruz, Fidel Herrera Beltran, and assistant director of Pemex’s north region, Jorge Andres Perez Fernandez, inaugurated the drilling project Jan. 1 in Tuxpan. Tuxpan is the closest port to Mexico City; Pemex maintains a facility on the Tuxpan River to build and maintain drilling rigs.
This is the first exploration project since Mexico’s Congress passed the 2008 energy reform bill in October 2008 (OGJ, Dec. 15, 2008, p. 18).
Noble Max Smith can drill in 7,000 ft of water. It’s under a 3-year contract to Pemex, from Aug. 1, 2008, to July 31, 2011. Noble said the rig was upgraded in second-quarter 2008, mobilized from the US to Mexico, and is working at a dayrate of $484,000.
Noble also has 10 jack up rigs working in Mexico’s Bay of Campeche, with contracts ending December 2009 to December 2011. Noble’s rigs in Mexico contributed 20% of the company’s overall revenue in the first 9 months of 2008, according to the company’s investor presentations in December.
Reindeer gas field development to proceed
The Apache Energy-Santos development of Reindeer gas field off Western Australia and the associated Devil Creek processing plant 45 km south of Dampier is back on track following Santos’ signing of CITIC Pacific as the project’s foundation gas buyer.
Under the $812 million (Aus.) contract, Santos will supply CITIC’s Sino Iron magnetite mining project at Cape Preston 100 km south of Dampier with 75 petajoules (69.75 bcf) of gas over 7 years beginning in the latter half of 2011. The gas will be used as generation fuel for Sino’s 450 Mw electric power plant now under construction.
Reindeer field, discovered in 1997 on permit WA-209-P, has reserves of 390-610 bcf of gas. The gas will be transported via subsea pipeline 105 km to the Devil Creek plant. Flow capacity will be about 215 terajoules/day (200 MMcfd). All the gas will be fed into the domestic market.
The project was deferred in December when Santos said there were delays in the execution of a gas sales agreement because of the poor financial climate.
Although Santos said the project is again viable, Clough Australia said it is still waiting to hear if its contracts for engineering, procurement, and construction of the Devil Creek plant and the offshore facilities at Reindeer will be reinstated.
Apache holds 55% of the project, and Santos holds 45%.
Nexus: Libra, Crux fields are separate structures
The successful Libra-1 wildcat drilled in Browse basin permit AC/P41 off Western Australia has confirmed that Libra field is a separate structure from nearby Crux field, said the permit’s partners.
Royal Dutch Shell PLC holds 65% interest in the permit; Mitsui holds 20%, and Nexus Energy, 15%.
Logging and pressure data indicate that Libra-1 intersected a 206-m gross gas column in a better-than-predicted reservoir section on the way to a total depth of 3,918 m.
The gas-water contact in the well is shallower than that encountered in Crux as well, also suggesting that Libra is a separate accumulation.
Nexus says the find has boosted confidence in the prospectivity of the Greater Crux region and provides additional incentive for follow-up drilling at the adjacent Auriga and Caelum prospects.
Libra-1 was drilled by the Ocean Epoch semisubmersible and is now plugged and abandoned as planned.
ExxonMobil eyes Sandakan basin exploration
ExxonMobil Corp. plans to invest as much as $100 million exploring for oil and gas in southwestern Philippine waters, press reports said.
The disclosure, contained in Philippines Department of Energy documents, refers to a mid-2008 farmout under which Mitra Energy Ltd., a private company registered in Hamilton, Bermuda, farmed out a 50% interest and operatorship of Service Contract 56 to ExxonMobil (OGJ Online, June 13, 2008). The Philippines DOE approved the farmout in July 2008.
The partnership plans to drill two deepwater exploration wells in 2009, Mitra Energy’s web site said.
SC 56 covers more than 8,600 sq km of acreage in as much as 3,000 m of water in the Sulu Sea northeast of Borneo Island in the Sandakan basin.
“The principle hydrocarbon play is contained within Miocene deepwater turbidite depositional systems in the distal setting of the Sandakan basin. Gravity-induced thin-skinned tectonism has given rise to a number of large toe-thrust anticlinal structures, which have significant hydrocarbon potential analogous to other circum-Borneo proven deepwater toe-thrust belts,” Mitra Energy said.
Norway awards four licenses to Lundin
Norway awarded Lundin Petroleum AB’s wholly owned subsidiary Lundin Norway AS four exploration license interests in the 2008 Norwegian Licensing Round, Awards in Predefined Areas (APA). The licenses are in the North Sea.
Lundin will operate Blocks 7/2, 4, 5, and 8 with a 60% stake and Blocks 16/2, 3, 5, and 6 with a 40% stake.
In addition, Lundin holds a 40% interest in Block 15/12 and a 30% interest in Block 25/7, 10.
Drilling & Production Quick TakesJapan protests Chinese drilling in E. China Sea
Japan said it “cannot accept” China’s development of the Tianwaitian gas field near a disputed part of the East China Sea, saying instead that the area should be under negotiation.
“The Japanese government expresses its regret that China is unilaterally developing the field,” said Chief Cabinet Secretary Takeo Kawamura, adding, “Japan cannot accept China’s unilateral development.”
Japanese Foreign Minister Hirofumi Nakasone, describing the Chinese actions as “regrettable,” called for the early resumption of negotiations between the two sides.
“I can’t say exactly when it would be, but I believe the most important thing right now is for working-level discussions on this issue to resume soon,” said Nakasone.
The governments of Japan and China agreed on joint development of the gas fields in June 2008.
The accord includes joint development in the area near the Asunaro (known in China as Longjing) gas field, and Japan’s investment in the development of the Shirakaba (known in China as Chunxiao) gas field.
The Tianwaitian field (known in Japan as Kashi) was not mentioned by name in the June agreement but Japan contends it is part of further negotiations and should be left undeveloped.
“Our understanding is that the status of the [fields] outside of the political agreement is blank. Therefore the status quo is the way it should be,” Kawamura said. But China disputes the Japanese claim.
“The gas field development activities of the Chinese side are being carried out within China’s inherent sovereign rights,” said foreign ministry spokesman Qin Gang.
According to a recent report in Japan’s Sankei Shimbun newspaper, China has already finished the drilling in Kashi-Tianwaitian, and “there is the strong possibility that China has entered the stage of production.”
Venture starts production from Grouse oil field
Venture Production PLC, Aberdeen, has brought Grouse oil field on Block 21/19 on stream in the UK Central North Sea.
The field is expected to produce 10,000 b/d of oil and 3.25 MMscfd of natural gas in 2009. Production is through a single subsea well tied back to the company’s operated Kittiwake platform–the production hub for the Greater Kittiwake Area (GKA). Natural gas will be used as fuel or exported via the Shell Fulmar line to St Fergus.
Venture said it saved money by laying Grouse’s required pipeline when it developed Chestnut and Stamford fields, which began production in 2008.
“Grouse has also made use of a pipeline tie-in point that was preinstalled during the construction of the Goosander infrastructure in 2006,” Venture said. Goosander started production in August 2006 in the GKA production hub.
Mallard oil field, also in the GKA, resumed production in mid-December following production optimization initiatives. It is a high-pressure, high-temperature subsea tieback to the Kittiwake platform.
Mike Wagstaff, chief executive of Venture, said Grouse was the third GKA satellite to have been brought into production since Venture assumed operatorship 5 years ago.
Venture operates Grouse with a 50% working interest. Its partner, Dana Petroleum PLC, holds the other 50%.
BC’s first commercial CBM project on line
GeoMet Inc., Houston, and Canada Energy Partners Inc., Vancouver, BC, began deliveries from British Columbia’s first commercial coalbed methane project near Hudson’s Hope west of Dawson Creek, BC.
Flow started on Dec. 31, 2008, from eight wells at the Peace River project, and GeoMet plans to book initial proved reserves as of that date.
The companies have drilled 12 production wells and four coreholes to Lower Cretaceous Gething coals that average 52 ft thick with 400 cf/ton across 50,788 acres. More drilling is planned in mid-2009.
GeoMet is operator with 50% interest, and Canada Energy Partners has 50%. Canada Energy Partners said the companies have invested more than $45 million in the project the past 8 years. The project has 315 potential well locations on 160-acre spacing.
Canada Energy Partners said the project’s modular, scalable gas treating and compression facilities will be strategic in commercialization of the Moosebar shale, the Montney shale, and other deeper formations. Exploration programs on Moosebar and Montney-Doig formations are under way on the lands covered by the project.
GeoMet said Peace River has thicker coal with higher gas content than its project in Alabama’s Cahaba basin. Operating costs are higher in Canada, but it expects a similar return because it pays no severance tax, no royalty for 5-7 years, and then 10% average royalty for the life of project.
US 2007 drilling outlays rise to $226.4 billion
US oil and gas drilling expenditures soared to a record $226.4 billion in 2007, more than doubling the previous record of $109.8 billion a year earlier, the American Petroleum Institute said on Jan. 5.
API said the Joint Association Survey of Drilling Costs for 2007, the latest year for which figures are available, showed that records also were set in average costs per well and per foot.
Average costs per US oil well grew 82% to $4 million in 2007 from $2.2 million, while per foot costs climbed 78% year-to-year to an average of $717 from $412, according to API. It said that average costs per domestic natural gas well rose 105% to $3.9 million in 2007 from $1.9 million in 2006 as average costs per foot grew 74% year-to-year to $604 from $348.
Total oil well expenditures jumped 94% to $72.3 billion in 2007 from $37.3 billion in 2006, while gas well expenditures grew by nearly 101% to $119.1 billion from $59.3 billion, API said.
Hazem Arafa, director of API’s statistics department, said strong demand and historically high prices increased competition for labor, services, and equipment, which pushed drilling costs higher along with record-high steel costs.
“But despite a doubling of the cost to drill and develop wells, we also witnessed a rise in both the number of wells drilled, which increased 4% from 2006, and the average depth of those wells, which increased 9%,” he continued.
API said the latest numbers showed more spending for gas wells (53%) in the US in 2007 than for oil wells (32%) for a 20th consecutive year despite exceptionally strong oil exploration. Dry holes represented the remaining 15% of the total, it indicated.
Processing Quick TakesExxonMobil to spend $1 billion in refineries
ExxonMobil Refining & Supply announced that it is planning to invest more than $1 billion in three refineries to increase the production of ultralow-sulfur diesel by about 6 million gpd.
The company is adding new units and modifying existing facilities at its 567,000-b/d Baytown, Tex.; 503,000-b/d Baton Rouge, La.; and 305,000-b/d Antwerp, Belgium, refineries.
The modifications and expansions to produce diesel with 15 ppm or less of sulfur are expected to be completed by 2010.
“Our increase in diesel production at these three sites will be equal to the diesel produced from about four average-size refineries,” said Sherman Glass, president, refining and supply.
Reliance Industries refinery starts operations
India’s Reliance Industries Ltd. (RIL) started operations Dec. 25, 2008, at its 580,000 b/d refinery at Jamnagar in western India. Reliance said it is now synchronizing and commissioning secondary units.
The facility, along with Reliance’s neighboring 660,000 b/d refinery, will form the world’s largest refining complex, having a total capacity of 1.24 million b/d.
RIL said it expects the refinery to reach full capacity shortly, but the company will likely have a slow ramp-up because of a slump in the global demand for products and relatively weaker refining margins.
The refinery is owned by RIL’s Reliance Petroleum Ltd. unit, in which Chevron Corp. holds a 5% stake.
RIL was expected to commission the refinery months ahead of its yearend schedule, but delayed its start as the global economic slowdown reduced demand for oil products, and refining margins crashed.
Axens secures petrochemical deal in Kazakhstan
JSC KazMunaiGaz will use Axens’ ParamaX technology for its proposed petrochemical complex, which it will integrate into the 104,500 b/cd Kazakhoil refinery at Atyrau in Kazakhstan. The value of the deal was not disclosed.
The Atyrau refinery processes as much as 5 million tonnes/year of oil from various fields in western Kazakhstan.
When completed, the 629,000 tonnes/year grassroots petrochemical plant, during 2012-13, will produce 496,000 tonnes/year of paraxylene and 133,000 tonnes/year of benzene from naphtha.
JSC Omskneftekhimproekt of Russia is performing the front-end engineering design for the petrochemical complex.
Petrovietnam seeks Dung Quat refinery partner
Petrovietnam plans to sell a 49% stake in its Dung Quat refinery, which is scheduled to go online in February (OGJ Online, Dec. 11, 2008).
“Petrovietnam would appraise the refinery’s value and negotiate with foreign partners before selling the stake,” said Petrovietnam chairman Dinh La Thang.
The Vietnamese firm, which plans to give preference to international partners committed to supplying oil to the refinery, is expected to begin talks with BP PLC next week.
Dinh said the negotiations would focus on price and quality, and the possibility that BP would provide at least 50% of the total oil for the refinery.
Petrovietnam has decided to import oil for the refinery as Vietnam’s own oil and gas reserves are limited and could earn the country more revenue as an export because they are of higher quality than that required by the new facility.
The Dung Quat refinery is about 98% complete, according to Dinh Van Ngoc, deputy general director of the Binh Son Petrochemical Co., which manages the refinery.
Dinh said the refinery’s capacity would stand at 50% in February, but would increase to 100% by yearend, when it will process some 6.5 million tonnes of oil.
Transportation Quick TakesIndonesia, China to revise Tangguh LNG price
Indonesia, building on earlier agreements, said it will move ahead with plans to renegotiate the price of LNG from the Tangguh field for export to China.
“We will refresh (the negotiation) in January 2009,” said Vice-Pres. Jusuf Kalla on a visit to the Tangguh LNG project at Bintuni Bay in West Papua province.
Kalla, who said the negotiations would take up the pricing formula and not just the price of the LNG, gave no indication of what his government planned to offer the Chinese.
In the original 25-year contract between Indonesia and China, the price had been set at $2.40/MMbtu and was based on an oil price of $20/bbl.
In later negotiations, the Chinese government agreed to raise the price to $3.80/MMbtu but the Indonesian government refused the offer, saying it was still too low.
In October, Indonesia denied that it was planning to delay the first shipments of LNG–due to begin in first quarter 2009–from Tangguh as a means of pressuring China to agree to a better price.
“We must respect the contract,” said Energy and Mineral Resources Minister Purnomo Yusgiantoro. “We are continuing negotiations, but as the negotiation has yet to reach an agreement, we must follow the contract,” he said (OGJ Online, Oct. 30, 2008).