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    Upstream News

    Occidental to spin off california assets into separate company

    Occidental Petroleum Corp.'s board of directors has authorized the separation of Occidental's California assets into an independent and separately traded company.

    According to Occidental, the new California company will be the state's largest natural gas producer and largest oil and gas producer on a gross-operated barrels of oil equivalent basis. The new company will also be the largest oil and gas mineral acreage holder in the state with approximately 2.3 million net acres, and will have major operations in the state's high-potential oil and gas basins, including Los Angeles, San Joaquin, Ventura, and Sacramento.

    Last year, Occidental's California business earned approximately $1.5 billion on a pre-tax basis. Earnings before income, taxes, depreciation and amortization were around $2.6 billion with capital expenditures of approximately $1.7 billion. Capital expenditures planned for 2014 were increased to $2.1 billion. The company is expected to a balance sheet with between $4 billion and $5 billion of funded debt.

    Occidental Petroleum Corp. will be headquartered in Houston with exploration and production operations in the Permian Basin and other parts of Texas, the Middle East region, and Colombia. It will also have a midstream and marketing segment and a chemical subsidiary, OxyChem. The company also plans to reduce its exposure to proprietary trading activities related to crude oil and other commodities.

    Stephen I. Chazen has agreed to remain as president and CEO through the 2016 Annual Meeting of Stockholders. The board also has asked Ambassador Edward P. Djerejian, who was elected as chairman of the board last May, to remain as chairman for an additional one-year term.

    The company expects to announce the California management team in the third quarter of this year and complete the separation by the end of 2014 or the early part of 2015.

    Sterne Agee analyst, Tim Rezvan, commented on Occidental's announcement of the California spin-off, saying, "We estimate 6-7% oil-focused production growth in California in '14, accelerating in '15 and beyond. We believe the segment could trade at a 7x 2014E EV/EBITDA multiple, two turns higher than where OXY shares trade. This news, combined with last night's repurchase news, should support shares today." Rezvan noted that Occidental has a 2.3 million net acre leasehold position in the state. "2013 production from California averaged 154 mboe/d (58% oil)," he stated, "and we estimate 2014 production will average 163 mboe/d (61% oil)."

    BP starts oil production from West Chirag in Caspian Sea

    BP says oil production has started from the new West Chirag platform in the Azeri sector of the Caspian Sea. The platform was commissioned for the $6-billion Chirag oil project in 2010 as part of the Azeri-Chirag-Gunashli (ACG) field development.

    More than $4 billion was allocated to construction of facilities and the pre-drill program, and the remainder will be spent on platform development well drilling. The investment should help optimize recovery from the ACG field, BP adds.

    The West Chirag facility has been installed in 558 ft of water between the existing Chirag and Deepwater Gunashli platforms. Its oil-handling capacity is 183,000 b/d and its gas export capacity is 285 MMcf/d (8 MMcm/d).

    Oil produced from the J05 well will be processed onboard and then exported to the Sangachal Terminal via a new infield pipeline linked to an existing 30-in. subsea export pipeline. Partners in the ACG development are BP (operator – 35.8%), SOCAR (11.6%), Chevron (11.3%), INPEX (11%), Statoil (8.6%), ExxonMobil (8%), TPAO (6.8%), ITOCHU (4.3%), and ONGC Videsh (2.7%).

    ICF: North American oil and gas production continues to accelerate

    North American oil and gas production continues to accelerate, says a new report from ICF International. In the short run, reduced gas-directed drilling activity will continue to slow gas production growth from "dry" gas plays such as the Haynesville Shale, the Greater Green River Basin, the Barnett Shale, and the Fayetteville Shale. However, these plays are likely to rebound as market growth firms gas prices.

    Conversely, liquids-rich plays have fared much better in the relatively low gas price environment that persisted throughout much of 2013. Consequently, US NGL production, which has increased by more than 600,000 barrels per day during the past five years, is expected to continue to grow and will likely double by the end of the projection.

    In today's relatively high oil price environment, output from the unconventional oil plays, such as the Bakken, the Cline, the Niobrara, and the Eagle Ford, are likely to continue to grow.

    While high oil prices could promote growth of bitumen production in Western Canada's oil sands, continued delays in construction of new crude transport capability present risks.

    Natural gas production

    US and Canada natural gas production grows by 1.8% per year (2.0% per year in the US and 1.1% per year in Canada). It grows to 121 Bcfd (+40 Bcfd: +36 Bcfd in the US and +4 Bcfd in Canada) by 2035.

    Unconventional gas (shale, tight, and coalbed methane) production grows by 3.2% per year (2.9% per year in the US and 5.6% per year in Canada), reaching 101 Bcfd (+50 Bcfd: +40 Bcfd in the US and +10 Bcfd in Canada) by 2035. Shale gas production grows by 3.9% per year (3.6% per year in the US and 6.6% per year in Canada), reaching 81 Bcfd (+46 Bcfd: +36 Bcfd in the US and +10 Bcfd in Canada) by 2035. Tight gas production grows by 1.5% per year, mostly in the US. It grows to 16 Bcfd (+4.5 Bcfd) by 2035. Coalbed gas production declines to 4.2 Bcfd by 2035 (from 4.8 Bcfd in 2013).

    Conventional (onshore and offshore) natural gas production continues to decline to 20 Bcfd (-10.4 Bcfd: -5.8 Bcfd in the US and -4.6 Bcfd in Canada) by 2035, an average decline rate of -1.9% per year.

    Offshore Gulf of Mexico (GOM) gas production declines in 2013 but production from deepwater recovers from the 2014 level. GOM gas production reaches 7.2 Bcfd (+3 Bcfd) by 2035, an average growth of 2.6% per year.

    The largest growth in natural gas production is from shale. Shale gas production accounts for more than 50% of all US and Canada gas production by 2016 and about two-thirds by 2035.

    Substantial growth from the Marcellus with an incremental change of nearly 13 Bcfd over the 2013 level, reaching 23 Bcfd by 2035.

    Other high growth areas include the Haynesville, Montney, Eagle Ford, Horn River, and Utica, with a 2013 to 2035 incremental change of 6.9 Bcfd, 6.0 Bcfd, 3.4 Bcfd, 2.8 Bcfd, and 2.2 Bcfd, respectively. Haynesville gas production declines in 2013 but recovers as gas prices firm. Eagle Ford development is primarily driven by liquids-directed drilling activity. Utica gas grows significantly from about 0.2 Bcfd in 2013, reaching more than 1 Bcfd by 2017 and 2.5 Bcfd by 2035.

    Gas liquids (NGLs) production

    Natural gas liquids (NGL) production in the US and Canada grows by 3.2% per year. NGL production reaches 6.4 million boe/d by 2035, double the 2013 level of 3.2 million boe/d. Major NGL production growth regions include the Marcellus (+0.81 million boe/d), Western Canada's Shales (including the Montney, Horn River, and several smaller plays; +0.73 million boe/d), Eagle Ford (+0.41 million boe/d), Utica (+0.35 milion boe/d), and the Bakken (+0.25 million boe/d).

    Crude oil and condensate production

    Robust growth of crude oil and condensate production in the US and Canada. Production grows to 18.2 million BPD (+7.2 million BPD) by 2035. The largest production growth is from oil sands in Alberta. Oil sands production grows by 4.9% per year, reaching 5.8 million BPD (+3.8 million BPD) by 2035. Production from shale/tight oil plays also grows significantly, at 4% per year, reaching 6.3 million BPD (+3.6 million BPD) by 2035.

    Production from the West Texas/Permian tight oil plays (including the Wolfberry, Cline, Avalon & Bone Springs, and other smaller plays) grows by 6.7% per year, adding a total of 1.3 million BPD by 2035.

    The Niobrara tight oil plays (including both the Denver Niobrara and Powder River Niobrara) grow at 8% per year. Crude oil production grows from 0.16 million BPD in 2013 to 0.85 million BPD by 2035 (+0.7 million BPD).

    The Bakken shale is the largest single tight oil play in North America, with incremental crude oil production of 0.65 million BPD by 2035.

    The Eagle Ford contributes roughly 0.6 million BPD of incremental oil production by 2035.

    Oil and condensate production from the deepwater Gulf of Mexico grows to 2.4 million BPD (+1.3 million BPD) by 2035, an average growth rate of 3.4% per year.

    Production from other conventional oil plays continues to decline by 1.5% per year, falling to 3.7 million BPD (down by 1.4 million BPD from today's level) by 2035.


    BRIEFS

    Schlumberger introduces new fracturing technique

    Schlumberger has introduced a new fracturing technique. According to the company, the BroadBand Sequence fracturing technique enables sequential stimulation of perforation clusters in wells drilled in unconventional reservoirs. The new technique sequentially isolates fractures at the wellbore to ensure every cluster in each zone is fractured, and according to the company, results in greater production and completion efficiency compared to conventional methods.

    The technique is suited for use in new wells and in recompletions, particularly for re-fracturing operations, given its ability to promote temporary cluster isolation without the aid of mechanical devices such as bridge plugs.

    This fracturing technique has been used in more than 500 operations conducted to date in plays including the Eagle Ford, Haynesville, Woodford, Spraberry and Bakken shales.

    Shell starts Mars b production

    Shell has started producing from the deepwater Mars B platform in the Gulf of Mexico. Producing is going through the Olympus installation making this the first deepwater GoM project to expand an existing oil and gas field with significant new infrastructure. Shell said this should extend the life of the greater Mars basin production to 2050 or beyond. When added to future Olympus production, the original Mars platform is expected to deliver a total of 1 Bboe.

    In addition to the Olympus drilling and production platform, the Shell Mars B development includes subsea wells at the West Boreas and South Deimos fields, export pipelines, and a shallow-water platform at West Delta 143. Olympus is in approximately 3,100 ft of water.

    Using the Olympus platform drilling rig and a floating drill rig, additional development drilling will enable ramp up to an estimated peak of 100,000 boe/d in 2016. Mars field produced an average of over 60,000 boe/d in 2013.

    Partners in the development are operator Shell, 71.5%; and BP, 28.5%.

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