OGJ Newsletter

GENERAL INTEREST Quick Takes

Oxy cuts another $800 million from capital spending  

Occidental Petroleum Corp. will further cut its 2020 capital spending to $2.7-2.9 billion from its original 2020 guidance of $5.2-5.4 billion, a midpoint reduction of 47%.

In early March, the company first cut 2020 capital spending by $1.7 million to $3.5-3.7 billion (OGJ Online, Mar. 10, 2020).

At current commodity prices, 2020 annual production from continuing operations is expected to be 1.275-1.305 MMboe/d, a reduction of 6% compared to prior guidance of 1.36-1.39 MMboe/d.

Oxy also will reduce 2020 operating and corporate costs by at least $600 million compared to the original 2020 plan, including salary reductions for executive leadership. The cost reductions are in addition to operating and overhead synergies of $1.1 billion expected to be fully realized this year, the company said. Overall, SG&A, Other Operating Expense, and Exploration Overhead are expected to be reduced to $500 million on a future quarterly run-rate basis. Operating cost reductions are expected to lower 2020 domestic operating costs to $7.00/boe.

Shell cuts $5 billion from 2020 cash capex  

Shell will reduce cash capital expenditure by $5 billion to $20 billion or below for 2020 in response to steeply falling oil demand and rapidly increasing supply.

The cut is one in a series of operational and financial initiatives that, together, are expected to contribute $8-9 billion of free cash flow on a pre-tax basis. The initiatives also are expected to reduce underlying operating costs by $3-4 billion/year over the next 12 months compared to 2019 levels and reduce working capital.

The company is still committed to its divestment program of more than $10 billion of assets in 2019-20 but timing depends on market conditions, the company said. Divestments of around $5 billion were completed in 2019.

The next tranche of the company’s share buyback program will not continue. The current share buyback tranche refers to the $1 billion share buybacks announced on Jan. 30.

Shell holds around $20 billion in cash and cash equivalents, $10 billion of undrawn credit lines under revolving credit facility, and access to commercial paper programs.

Chevron cuts 2020 capital spending by $4 billion

Chevron Corp. has cut its 2020 capital spending plan by $4 billion, or 20%, to $16 billion, in response to market conditions.

The cuts are expected to occur across the portfolio and are estimated to be allocated as a $2 billion cut in upstream unconventionals, primarily in the Permian Basin; a $700 million cut in upstream projects and exploration; a $500 million cut in upstream base business spread broadly across the company’s US and international assets; and an $800 million cut in the downstream, chemicals, and other segments.

Cash capital and exploratory expenditures are expected to decrease by $3.3 billion to $10.5 billion in 2020. Total capital and exploratory spending in the second half of 2020 is expected to be about $7 billion, an annual run rate 30% lower than the approved budget announced in December 2019.

Excluding 2020 asset sales and price related contractual effects, the company expects 2020 production to be roughly flat relative to 2019. Note that Chevron’s net production increases about 20,000 boe/d for each $10 movement lower in Brent oil prices due to contractual effects. Permian production by the end of the year is expected to be about 125,000 boe/d, or 20%, below prior guidance.

The company will respond to market conditions by “deferring short-cycle investments and pacing projects not yet under construction,” said Jay Johnson, executive vice-president of upstream, and is focused on “completing projects already under construction that will start-up in future years.”

Additionally, the company has suspended its $5-billion annual share repurchase program after repurchasing $1.75 billion of shares during the first quarter.

Exploration & Development Quick Takes 

SOCAR, Equinor confirm Karabagh oil field discovery  

State Oil Co. of Azerbaijan Republic (SOCAR) and Equinor confirmed a discovery in Karabagh field 120 km offshore, 120 km east of Baku, in the Azerbaijan sector of the Caspian Sea. Estimated size of the discovered volumes of oil and gas are satisfactory for pursuing commercial development of the Karabagh field, SOCAR said in a release Mar. 19.

Drilling of the first appraisal well at Karabagh oil field started Dec. 23, 2019. The well was drilled in 180 m of water by the Dada Gorgud semi-submersible drilling rig operated by SOCAR’s Caspian Drilling Co. (CDC). The reservoir is at a depth of 3.4 km.

Karabagh “is the first oil field discovered during the independence period of our country and its oil reserves estimated more than 60 million tons,” said SOCAR’s president, Rovnag Abdullayev.

The consortium operated by Caspian International Petroleum Co. (CIPCO) drilled three exploration wells in the Karabagh PSA signed in 1995: two wells found gas in the southeast portion of the structure and the third well indicated presence of oil in the western part of the structure. In 1999, the PSA was terminated due to the non-commercial discovery.

In May 2018, SOCAR Karabagh and Equinor signed an equal share risk service agreement related to development of the field.

Neptune Energy discovers oil in Rhine Valley exploration 

Neptune Energy discovered oil in the Schwegenheim exploration well in the Rhine Valley, Germany. Further assessment is required to determine if oil can be produced economically from the structure. The well has been suspended.

Drilling operations were carried out to a depth of 2,600 m between September and November 2019. The Bunter sandstone reservoir, equivalent to the nearby Römerberg structure, was dry but two secondary target upper layers were oil bearing.

Up to 1,500 bbl of crude oil from this well was transported to the 14.9 million-tpy Mineraloelraffinerie Oberrhein GMBH (MiRO) refinery in Karlsruhe.

Neptune will apply to the Rhineland-Palatinate state responsible mining authority for necessary permits for further production in Schwegenheim.

Neptune Energy is operator (50%) with partner Palatina GeoCon (50%).

CNOOC: Kenli 6-1 discovery in Bohai Bay further proves exploration potential  

The Kenli 6-1 oil discovery in China’s Bohai Bay is expected to be the first large-sized oil field in Laibei lower uplift in southern Bohai basin, according to CNOOC Ltd.

In the basin with an average water depth of 19.2 m, the KL6-1-3 discovery well was drilled and completed in water depth of 1,596 m. It encountered oil pay zones with a total thickness of 20 m. The well was tested to produce around 1,178 b/d of oil.

The successful exploration of Kenli 6-1 further proves the exploration potential of the Neogene lithologic reservoir in the Laizhou Bay, the company said.

Drilling & Production Quick Takes 

Equinor halts US onshore drilling, trims 2020 spend by $3 billion 

Equinor is halting US onshore drilling and completions as part of a plan to cuts its 2020 spending by $3 billion. The company is reducing 2020 capex by roughly 20% to $8.5 billion from $10-11 billion. The company also cut exploration spending by $400 million to $1 billion and operating costs by around $700 million.

Equinor has been developing and producing onshore oil and gas in the US since 2008. Its portfolio is focused on the Bakken play in North Dakota and the Marcellus-Utica formations in the Appalachian basin. Equinor’s onshore US production of 321,000 boe/d includes Eagle Ford shale assets sold to Repsol in late 2019 (OGJ Online, Nov. 8, 2019).

The company says the spending changes will allow it to be organic cash flow neutral before capital distribution at an oil price of $25/bbl for the balance of the year. In 2014 Equinor said it needed an average oil price of around $100/bbl to be organic cash flow neutral before capital distribution.

These cost reductions come in addition to Equinor’s already announced suspension of its $5-billion, 4-year stock buy-back program. 

FAR questions Sangomar development timetable,  

Sangomar oil field partner FAR Ltd. has flagged problems for the project development offshore Senegal due to the fall in oil price and the restrictions caused by the COVID-19 virus.

The company said it is working with operator Woodside and other JV partners to explore and evaluate all options to preserve and enhance the value of the development.

Further details—including how costs can be reduced, expenditure delayed, or both and whether there will be any impact on the timeline to first oil—will be released upon completion of the review, FAR said.

FAR added that discussions with financiers are materially compromised in the present market conditions.

The $4.2 billion Sangomar development achieved FID in January (OGJ Online, Jan. 15, 2020). The concept is a stand-alone FPSO facility connected to 23 subsea wells and supporting subsea infrastructure.

The FPSO is expected to have a production capacity of 100,000 b/d of oil and will process the oil for direct offloading to export markets via tankers. First oil is targeted for early 2023.

The FPSO is being designed to allow for integration of potential future development phases, including gas export to shore and future sub-sea tie backs.

The JV comprises Woodside Energy (Senegal) BV, Capricorn Senegal Ltd., FAR Ltd., and Petrosen.

FAR also has temporarily suspended drilling plans for its offshore Gambia blocks A2 and A5 where it is operator (OGJ Online, Oct. 1, 2019).

Husky suspends West White Rose construction 

Husky Energy is suspending major construction activities related to its West White Rose project (OGJ Online, July 26, 2018). The action was taken to prevent transmission of the COVID-19 virus.

The company expects West White Rose to reach 75,000-b/d peak production in 2025.

Production from White Rose field and its satellite extensions, 350 km off the coast of Newfoundland and Labrador, Canada, is continuing with enhanced workforce control measures introduced to ensure ongoing safe operations on Husky’s SeaRose FPSO.

Husky said it will provide a business and capital spending plan update in due course.

Sole gas field initiates flow to Orbost plant 

Cooper Energy Ltd., Adelaide, has advanced Sole gas field project in eastern Bass Strait offshore Victoria with the first flow of gas from the field to the Orbost onshore processing plant (OGJ Online, Mar. 18, 2019).

The gas is being used to commission the plant’s new raw gas processing facilities. The gas will be used during the second, and final, phase of the plant commissioning program.

Cooper said the initial gas production and processing levels will be small volumes, however gas production is expected to increase gradually as the second phase commissioning progresses towards completion. The program also involves performance of a full-rate production test.

Once the commissioning has been successfully completed gas supply from Sole to customers under long-term contracts can begin.

Full production from the field is expected by the end of March.

PROCESSING Quick Takes 

Liberia gears up for commissioning of new refinery 

Conex Group JV Ltd.’s Conex Petroleum Group Inc. is progressing with a plan to install a 10,000-b/d modular refinery at Conex Petroleum Service Inc.’s existing petroleum storage terminal in Monrovia, Liberia.

A factory acceptance test for the modular refinery remains on schedule, VFuels LLC—the unit’s Houston-based manufacturer—said in a post to its official LinkedIn page.

Launched in April 2019, the modular refinery comes as part of the second-phase development of Conex’s 55,000-tonnes petroleum storage terminal commissioned in 2016 at Monrovia, Conex said in a May 2, 2019, release.

Alongside helping to ensure job creation and petroleum product sufficiency for Liberia, the refinery also will create additional revenue through royalties to partner Liberian Petroleum Refinery Co. (LPRC), taxes to the government, and community development projects, said Cherif M. Abdallah, Conex’s chairman and chief executive officer.

While independent Liberian-owned Conex did not disclose a definitive timeframe for commissioning of the new project, the refinery previously was scheduled for startup within 24 months of the project’s April 2019 launch, according to reports from local Liberian media.

Now responsible for storing and handling petroleum and petroleum products, LPRC said in its 2011-16 strategic plan issued in October 2012 that it intended to conduct feasibility studies for construction of a 50,000-b/d refinery in Liberia (OGJ Online, June 21, 2016). The country relies exclusively on fuel imports from surrounding regions as it is without a refinery until startup of Conex.

Neste delays Porvoo refinery turnaround  

Neste Corp. is delaying 11 weeks of routine planned maintenance previously scheduled for second-quarter 2020 at its 10.5 million-tonnes/year refinery in the Kilpilahti industrial area of Porvoo, Finland, as part of the operator’s effort to limit the spread of the coronavirus (COVID-19) pandemic.

Following the government of Finland’s declaration of a state of emergency in the country due to the COVID-19 outbreak, Neste has determined the major turnaround—which occurs every 5 years—will need to be executed in phases, with only the most business-critical maintenance works and regulatory inspections to be executed in the originally scheduled April-June window, the operator said on Mar. 23.

Neste—which must now restart planning of the turnaround as a result of the delay—said it expects to define a new execution schedule for remaining maintenance works and investment projects by the end of third-quarter 2020. Those outstanding works and projects, however, will not be completed until 2021, according to the operator.

While Neste estimates negative impact of the turnaround’s now-revised first phase of business-critical maintenance works and regulatory inspections on comparable operating profit presently stands at about €85 million for mainly second-quarter 2020, the company warned that figure could change given the exceptional and ongoing uncertainty created by the current business environment.

Before the newly announced postponement, Neste estimated the scope of the originally planned €450-million Porvoo turnaround to negatively impact its 2020 comparable operating profit by a total of €220 million, according to a Feb. 7 presentation to investors.

Neste—which confirmed in its 2019 annual report the Porvoo refinery carried out of a series of unidentified preliminary activities for the 2020 major turnaround last year—has not disclosed details of specific projects to be executed as part of the postponed maintenance event, which as originally planned was to require more than 6,000 workers to complete.

The turnaround, however, will involve regulatory inspections, maintenance works, and selected asset improvement initiatives aimed at ensuring safety, availability, and competitiveness of the Porvoo refinery for what Neste calls the next operating cycle, according to information available in the operator’s most recent reports to investors and on its website.

Rompetrol begins maintenance at Petromidia, Vega refineries 

Rompetrol Rafinare SA—jointly owned by Kazakhstan’s state-owned KazMunaiGas subsidiary KMG International Group 54.63% and Romania’s Ministry of Economy, Energy & Business Environment 44.69%—has started nearly 7 weeks of planned maintenance at its 5 million-tonne/year Petromidia refinery in Navodari, Romania, on the Black Sea.

The turnaround, which began on Mar. 13 and will run until Apr. 30, will include general maintenance at both the refining and petrochemical operations of Petromidia’s site, Rompetrol Rafinare said in a filing to the Bucharest Stock Exchange.

During the same period, Rompetrol Rafinare said it also will partially reduce production activities at its 8,000-b/d Vega refinery in Pahova County, near Ploiesti, Romania, for a series of turnaround works. The operator said its decision to carry out maintenance at the Vega manufacturing site partially results from a reduction in raw and semifinished materials that will be delivered to the refinery during the Petromidia shutdown period.

While the Petromidia refinery will be fully offline during the scheduled turnaround, Rompetrol Rafinare said it will cover demand for petroleum products from its own existing stocks or those secured from the regional market.

The operator, however, disclosed no details regarding the proposed maintenance projects to be undertaken at either the Petromidia or Vega sites.

Announcement of the planned maintenance event follows the recent startup of a new LPG recovery system at the Petromidia refinery in late February.

Designed to remove organic sulfur compounds and hydrocarbons from coking gases before they are sent to desulfurization plants and then into the refinery’s fuel gas system, the $4.6-million LPG recovery system has a maximum flow-rate processing capacity of 16,000 cu m/hr to ensure improved production flow through recovery and combustion of gases, as well as enable a major reduction of sulfur from gases discharged to the refinery baskets well below the limit imposed by European environmental regulations, Rompetrol Rafinare said on Feb. 24.

TRANSPORTATION Quick Takes 

Ineos pushes Forties system maintenance to August 

Ineos Forties pipeline system (FPS) has delayed its planned summer shut down between Unity platform and landfall at Cruden Bay, northeast Scotland, in the face of the COVID-19 pandemic. Planned to begin June 16, the maintenance closure will now not start before August.

The FPS 36-in. OD subsea pipeline extends 169 km across the North Sea from the Forties Charlie platform via the Forties Unity platform to Cruden Bay. From there, the 36-in. OD FPS landline runs 209 km south to the Kinneil terminal at the Kerse of Kinneil, Grangemouth, via three pumping stations at Cruden Bay, Netherley, and Brechin which provide booster compression. Pipeline capacity is 610,000 b/d.

Maintenance affected by this decision includes: 10-12 weeks of work on the 225,000-b/d Train 3 crude stabilizer and gas processing unit at Kinneil; 3 weeks of work on the pipeline’s entrance to Kinneil; and 32 days of work to replace the valves on the Graben Area Export Line’s pig receiver.

Ineos said it is “mindful of the benefits of completing this work to the future operation of FPS and the risks of not going ahead,” but that it “recognizes the importance of maintaining a flow of oil and gas through FPS during the current situation.” It also said that there had been an “overwhelming desire” to delay the shutdown on the part of its customers.

Sempra awards Port Arthur LNG EPC contract  

Sempra Energy and Bechtel’s respective subsidiaries, Port Arthur LNG LLC and Bechtel Oil, Gas, and Chemicals Inc., have signed a fixed-price engineering, procurement, and construction (EPC) contract for the 13.5 million tonne/year (tpy) Port Arthur LNG liquefaction facility. As part of the EPC contract, Bechtel will perform detailed engineering, procurement, construction, commissioning, startup, performance testing, and operator training. The agreement also includes continuing pre-final investment decision (FID) engineering.

Port Arthur LNG will include two liquefaction trains, two LNG storage tanks, a marine berth and associated loading equipment, and related infrastructure necessary to provide liquefaction services. The project site sits on nearly 3,000 acres of land along three miles of the Sabine-Neches waterway and has the potential to become one of the largest LNG export projects in North America, with expansion capabilities of up to eight liquefaction trains and 45 million tpy.

In January, Sempra LNG signed an interim project participation agreement with Aramco Services Co., a subsidiary of Saudi Aramco, for Port Arthur LNG. This followed a heads of agreement between the two companies in May 2019 for the potential purchase of 5 million tpy of LNG and a 25% equity investment in the project. In December 2018, Port Arthur LNG entered into an agreement with Polish Oil and Gas Co. for the sale and purchase of 2 million tpy.

Port Arthur LNG received authorization from the US Department of Energy to export domestically produced LNG to countries that do not have a free trade agreement with the US in May 2019. Additionally, the Federal Energy Regulatory Commission issued the approval to site, construct, and operate the liquefaction plant in April 2019.

Pembina receives Jordan Cove, Pacific Connector FERC approval 

Pembina Pipeline Corp. received approval from the US Federal Energy Regulatory Commission for its proposed 7.8 million tonne/year Jordan Cove LNG liquefaction terminal in Coos Bay, Ore., and 229-mile, 36-in. OD Pacific Connector gas pipeline, connecting Jordan Cove to the Ruby and Gas Transmission Northwest pipelines near Malin, Ore.

Jordan Cove will use five liquefaction trains and 320,000 cu m of storage divided between two tanks. Pacific Connector’s planned capacity is 1.2 bcfd.

Pembina, which acquired Jordan Cove in 2017, expects to complete the project in 2025.