GENERAL INTEREST — Quick Takes
ExxonMobil first-quarter earnings plunge $3.1 billion
ExxonMobil Corp. posted first-quarter earnings of $1.8 billion compared with $4.9 billion a year earlier. The impacts of sharply lower commodity prices and weaker refining margins were partly offset by strong chemical results.
Upstream earnings declined $2.9 billion from first-quarter 2015 to a loss of $76 million. Lower liquids and gas realizations decreased earnings by $2.6 billion, the firm says.
Production increased 1.8% from the year-ago period. Liquids production totaled 2.5 million boe/d, up 261,000 boe/d, while natural gas production was 10.7 bcfd, down 1.1 billion cu ft/d from 2015. Project ramp-up was partly offset by regulatory restrictions in the Netherlands, field decline, and asset management impacts.
US upstream operations recorded a loss of $832 million, compared with a loss of $52 million in first-quarter 2015. Non-US upstream earnings were $756 million, down $2.2 billion from the prior year.
Downstream earnings were $906 million, down $761 million year-over-year. Weaker margins cut earnings by $860 million. Volume and mix effects increased earnings by $10 million. All other items, primarily favorable foreign exchange effects, increased earnings by $90 million.
Earnings from US downstream were $187 million, down $380 million year-over-year. Non-US downstream earnings of $719 million were $381 million lower than last year.
Chemical earnings of $1.4 billion were $373 million higher than the first-quarter 2015 total. Improved margins increased earnings by $250 million. Favorable volume and mix effects increased earnings by $80 million. All other items, primarily lower expenses, increased earnings by $40 million.
Halliburton, Baker Hughes end merger plans
Halliburton Co. and Baker Hughes Inc. have ended their plan to merge (OGJ Online, Apr. 6, 2016).
Halliburton Chairman and CEO Dave Lesar cited "challenges in obtaining remaining regulatory approvals and general industry conditions that severely damaged deal economics."
Baker Hughes Chairman and CEO Martin Craighead noted the complexity of the deal and said, "A solution could not be found to satisfy the antitrust concerns of regulators, both in the United States and abroad."
The US Justice Department last month filed a lawsuit opposing the merger, the value of which was estimated at $34 billion when announced in November 2014. Earlier, the European Commission expressed concerns about antitrust aspects of the deal. Halliburton will pay Baker Hughes a termination fee of $3.5 billion.
Ultra Petroleum seeks bankruptcy protection
Unable to reach a debt-restructuring deal for its $3.9 billion in unsecured debt, Ultra Petroleum Corp. filed for Chapter 11 bankruptcy protection on Apr. 29 in Houston.
The Houston independent skipped a series of interest payments leading up to Apr. 1, and by mid-April faced a lawsuit from Rockies Express Pipeline LLC alleging breach of contract and seeking damages.
"During the forbearance period under the waiver agreements, we have attempted to and are continuing to negotiate a restructuring of our indebtedness, but, as of the date of this quarterly report on Form 10-Q, we have not been successful at accomplishing our plan," Garland Shaw, Ultra chief financial officer, explained in the US Securities and Exchange Commission filing.
Ultra primarily focuses on developing natural gas reserves in Pinedale and Jonah fields of Wyoming's Green River basin. The firm also has an oil development under way in Three Rivers field in Utah's Uinta basin, and a second natural gas position in the Marcellus shale of Pennsylvania's Appalachian basin.
During fourth-quarter 2015, Ultra recorded a noncash ceiling test writedown of $3.1 billion in the firm's carrying value of oil and gas properties due to low oil and gas prices.
Midstates Petroleum files bankruptcy
Midstates Petroleum Co. Inc. and Midstates Petroleum LLC, Tulsa, have filed for voluntary bankruptcy and will reorganize under a prearranged financial restructuring. Midstates expects to conduct business as usual during bankruptcy proceedings.
The independent producer focuses on oil fields in the Mississippian Lime play in Oklahoma and the Anadarko basin in Texas and Oklahoma. It also has operations in the Upper Gulf Coast Tertiary trend of central Louisiana.
Exploration & Development — Quick Takes
EQT to acquire Marcellus acreage for $407 million
EQT Corp., Pittsburgh, has agreed to acquire 62,500 net acres and current production of 50 MMcfd of gas equivalent in the Marcellus shale from Statoil USA Onshore Properties Inc. for $407 million. The deal is expected to close on or about July 8.
Primarily in Wetzel, Tyler, and Harrison Counties, W.Va., the acquired acreage is within EQT's core development area and complements EQT's adjacent operations in Wetzel County.
The deal includes 500 undeveloped locations that are expected to have an average lateral length of 5,600 ft. Because much of the acquired acreage is contiguous with EQT's existing development area, the lateral length of 106 existing EQT locations can now be extended from 3,000 to 6,500 ft.
In line with the EQT's consolidation strategy, the deal increases EQT's core undeveloped Marcellus acreage by 29%. The deal also includes drilling rights on an estimated 53,000 net acres that are undeveloped and prospective for the deep Utica.
The acquired assets include 31 Marcellus wells, 24 of which are producing. Of the seven others, three are complete and not online, and four are drilled but not complete.
The resource potential of the acreage is estimated at 9.2 tcf, and 87% of the acreage is either held by production or has lease expiration terms that extend beyond 2018. The acreage has 84% net revenue interest.
Statoil entered US shale in 2008 by forming a Marcellus joint venture with Chesapeake Energy Corp. In 2012, Statoil expanded its Marcellus footprint in deals with Grenadier Energy Partners LLC, PetroEdge Energy LLC, and Protege Energy LLC (OGJ Online, Dec. 19, 2012).
In late 2014, Statoil divested 30,000 net Marcellus acres with natural gas production of 29 MMcfed in West Virginia and southwest Pennsylvania to Southwestern Energy Co. for $394 million (OGJ Online, Dec. 23, 2014).
Aminex moves ahead on Tanzania producer
Aminex PLC plans to move ahead on its Ruvuma block onshore southern Tanzania near the Mozambican border. Aminex reported a loss of $3.78 million for 2015. It noted in its report, "2016 will be the year when Aminex begins to reap rewards from a decade of exploration and development in Tanzania."
In 2012, the Ntorya-1 well flowed at a maximum rate of 20.1 MMscfd of gas and 139 b/d of 48° gravity condensate (OGJ Online, June 28, 2012). At the time, the company cited a strong commercial potential for the discovery but has been slow to develop the region.
Aminex completed a new seismic program in the vicinity of its Ntorya-1 discovery in 2015, the design of which is being used to identify the channel fairway associated with the Teritary and Cretaceous reservoirs test in the Ntorya-1.
The company is obligated to drill a minimum of four exploration wells by yearend. Ntorya-2 will spud this summer to appraise Ntorya-1, with Ntorya-3 following to test the main channel system.
Earlier this month Aminex subsidiary Ndovu Resources Ltd. started gas production from its Kiliwani North field on Songo Songo Island, 15 km off mainland Tanzania (OGJ Online, Apr. 7, 2016). Once commercial rates have been established, the field is expected to produce at a rate of 25-30 MMcfd. The company will sell gas directly at the wellhead for a price of $3.07/Mcf.
The regional gas pipeline, under construction through 2015, was developed by Tanzania Petroleum Development Corp. Aminex noted the pipeline increases commercial potential for further discoveries in its Ruvuma basin acreage.
Aminex is Ruvuma block operator with 75% interest, and Solo Oil PLC has 25%.
Drilling & Production — Quick Takes
Alberta wildfire forces oil sands production cuts
A wildfire raging in the Regional Municipality of Wood Buffalo nearby Fort McMurray, Alta., has forced the mandatory evacuation of tens of thousands of people from the area and has caused many oil sands operators to cut production.
"The wildfire 1 km west of Gregoire in Fort McMurray remains out of control and has burned approximately 2,650 hectares," reported Alberta's Agriculture and Forestry Ministry.
Suncor Inc., which owns and operates an oil sands facility 25 km north of Fort McMurray, last reported its facility was in "a safe condition" but that it would be reducing production at its regional facilities "in order to allow employees and their families to get to safety."
Suncor said it was working with regional emergency response teams to aid in the evacuation efforts.
Suncor said other producers in the area, including Nexen Inc. and Canadian Natural Resources, are working on their own contingency plans.
In a statement, CNR said, "We are working to ensure that any potentially affected [CNR] workers who are residents of Fort McMurray are provided support during this time. We have provided accommodation at our camp for approximately 800 people from Fort McMurray, which includes employees and their families. We have offered the support of our aerodrome services to government officials for firefighting efforts and a portion of our firefighters and equipment are in the city helping to fight fires. Many people are currently moving in and out of camp, and daily operations remain stable."
Royal Dutch Shell PLC, meanwhile, has reportedly made its Albian Village work camp available to any Fort McMurray residents who need somewhere to stay.
Suncor to buy additional 5% of Syncrude
Suncor Energy Inc. is to buy an additional 5% of Syncrude Canada Ltd. for $937 million (Can.) from the Canadian subsidiary of Murphy Oil Corp. The purchase will bring Suncor's interest in Syncrude to 53.74% and close out Murphy's participation (OGJ Online, Dec. 9, 2015).
Suncor's share of Syncrude production in the first quarter averaged 112,800 b/d vs. 35,200 b/d a year earlier, primarily due to Suncor's acquisition of Canadian Oil Sands Ltd., which held 36.74% in Syncrude (OGJ Online, Mar. 22, 2016).
Suncor also reported first-quarter operating losses of $500 million, driven in part by low commodity prices, wider bitumen differentials to Western Canadian Select, and weak benchmark refining margins.
It said record production from Firebag (199,000 b/d) and MacKay River (36,800 b/d) led to record oil sands operations production of 453,000 b/d.
Oil sands production in the second quarter is expected to decrease as a result of an Upgrader 2 turnaround that began at the end of the first quarter.
The transaction with Murphy is subject to closing conditions, including regulatory approval under the Competition Act. It is expected to close by the end of the second quarter and will be effective Apr. 1.
Murphy said Syncrude has been an integral piece of its production and reserve base for more than 22 years. The sale will further focus Murphy's efforts on "onshore unconventional space in North America."
Statoil halts output at Gullfaks B after helicopter crash
Thirteen were declared deceased after a CHC helicopter on assignment for Statoil ASA crashed on Apr. 29 outside Turoy in Fjell municipality outside Bergen, Norway.
Two pilots and 11 passengers were on board the helicopter while it was en route to Bergen from the Gullfaks B platform on Block 34/10 in the northern portion of the Norwegian North Sea. Production at Gullfaks B was temporarily shut down, and emergency personnel were sent to assist those on board.
Late on Apr. 29, Statoil reported that the 11 passengers are employed by the following companies: Halliburton, Aker Solutions, Schlumberger, Welltec, Karsten Moholt, and Statoil. The two pilots are employed by CHC.
Production resumes from Oyo-8 well offshore Nigeria
Production has resumed from the Oyo-8 well offshore Nigeria after the Island Constructor light well intervention (LWI) vessel completed work, Erin Energy Corp. reported on May 3.
The vessel was dispatched to Oyo-8 in March for service on the well's subsurface controlled subsurface safety valve, which failed to reopen after a planned production curtailment on Oyo field (OGJ Online, Mar. 29, 2016).
Erin Energy will now ramp up production from the well over the next few days to pre-shut in levels of 7,000 b/d of oil. Production from the Oyo-8 and Oyo-7 wells began in May and June 2015, respectively (OGJ Online, June 18, 2015). Total output from the two wells in 2015 was 1.6 million bbl of oil.
DNO boosts Kurdistan drilling, production
DNO ASA, a Norwegian oil and gas operator controlled by RAK Petroleum PLC, reported it is using increased revenues for a drilling program at Tawke oil field in the Kurdistan region of Iraq, and executives said the company is on track toward increased profitability for 2016 (OGJ Online, Aug. 20, 2015).
Earnings statements showed DNO reported its first quarterly profit from operating activities since 2014. First-quarter 2016 revenue was just under $50 million, up from $26 million for the same quarter last year. DNO said earnings before interest, tax, depreciation, and amortization were nearly $24 million vs. losses of more than $34 million for first-quarter 2015.
First-quarter Tawke workovers to three wells reversed production declines, adding 10,000 b/d of incremental oil output. The three workovers cost $1.5 million total and were completed in about 30 days. Seven workovers are planned this year.
DNO also plans to drill five new Tawke production wells, three targeting the field's main Cretaceous reservoir and two targeting the shallower Jeribe reservoir.
Tawke first-quarter production averaged 91,700 b/d, of which 87,200 b/d went into an export pipeline through Turkey. Closure of the Turkish export pipeline during the second half of February and first half of March hampered output.
Once pipeline operations were restored, production averaged 118,900 b/d in April, of which 117,800 b/d was exported.
Later this year, DNO plans to drill an appraisal well to evaluate the Peshkabir discovery. If successful, Peshkabir could be quickly tied into existing infrastructures. Excluding Peshkabir, DNO has set a Tawke production target of 135,000 b/d following its 2016 investments.
PROCESSING — Quick Takes
Fatality halts work on Albertan polyethylene project
Nova Chemicals Corp. has halted construction on the Polyethylene 1 (PE1) plant expansion project at its ethylene and PE complex in Joffre, near Read Deer, Alta. (OGJ Online, July 1, 2013), following an industrial accident at the site.
Nova Chemicals suspended work at the PE1 construction site on Apr. 27 after a contractor operating at a stationary crane suffered severe trauma and subsequently died as a result of coming into contact with unidentified equipment, Bill Greene, senior vice-president of Nova Chemicals, said in a statement.
With construction activities suspended and the site now secured, regulatory authorities have launched an investigation into the incident.
In the coming days and weeks, the company will continue to work with the authorities, its partners, and its safety leaders to fully understand the cause of the tragedy and identify any changes it may need to make to ensure the safety of its employees, said Nova Chemicals CEO Todd Karan.
Work at the PE1 construction site remains suspended, Karan added. A timeframe for the restart of construction activities was not disclosed.
Designed to expand PE capacity at the Joffre site by 40%, the PE1 project includes installation of a 450,000-tonne/year single-train linear low-density PE unit, as well as associated equipment, as part of the company's Nova 2020 growth strategy (OGJ Online, Aug. 15, 2014; June 13, 2014; Mar. 3, 2014)
Eni advances plans for Zohr gas processing plant
Eni SPA is moving forward with plans to build the first of two natural gas plants in Egypt as part of its program to increase processing capacity for gas from its deepwater Zohr development in the Mediterranean offshore Shorouk concession (OGJ Online, Mar. 10, 2016; Feb. 26, 2016; Sept. 7, 2015).
Construction is already under way on the planned processing plant and associated gathering installations in Port Said, the Egyptian Ministry of Petroleum said.
The processing plant follows Eni's decision to accelerate production from Zohr field, the first two development phases of which previously were to use existing infrastructure and processing capacities.
With the Zohr development now on a fast track, however, the firm amended the project scope to add more onshore processing and pipeline capacities to accommodate the 2017-19 startup timeline, according to Eni's strategy update for 2016-19.
Contracts were signed and civil works already under way for the plant as of March, Claudio Descalzi, Eni's chief executive officer, said at the time.
Expedited as part of an effort to reduce costs and financial exposure, Zohr's accelerated 1-bcfd startup phase is scheduled to begin production from six subsea wells connecting via a gas pipeline to the onshore plant at Port Said by yearend 2017 (OGJ Online, Feb. 22, 2016).
The project's second phase, or the accelerated ramp-up-to-plateau, will add another 14 wells to boost production to 2.7 bcfd from 2019.
Second-phase plans also include another gas line as well as an additional onshore processing plant, according to a January presentation from Eni.
The two gas processing plants will each host four 350-MMcfd processing trains. Eni expects a total capital investment of less than €12 billion for both phases of the Zohr development.
Marcellus shale due first methanol plant
Primus Green Energy Inc. (PGE), Hillsborough, NJ, has signed an offtake agreement with methanol distributor Tauber Oil Co., Houston, to sell production from PGE's planned gas-to-liquids methanol plant in the Marcellus shale.
Tauber Oil will offtake all 160 tonnes/day of methanol production from the plant, which will be the first in the region to convert low-cost Marcellus feedstock into methanol, PGE said.
As part of the agreement, Tauber Oil subsidiary Interconn Resources will supply natural gas to PGE's plant.
The plant's first 160-tonne/day production train is scheduled for startup in fourth-quarter 2017, PGE said.
PGE has future plans to add another three trains that would expand the site's total methanol production capacity to 640 tonnes/day, and will reveal the proposed plant's precise location in the coming months.
TRANSPORTATION — Quick Takes
Shell cancels FLNG orders for Browse development
Royal Dutch Shell PLC has cancelled a $4.6-billion contract with South Korean shipbuilder Samsung Heavy Industries Co. Ltd. for three floating LNG vessels. The vessels, ordered in June 2015, were earmarked for development of the Browse gas-condensate fields offshore the Kimberley coast of Western Australia for the Woodside Petroleum Ltd.-led consortium.
However, the Browse FLNG project was postponed indefinitely in March this year because of the poor prevailing economic and market environment (OGJ Online, Mar. 24, 2016).
Up to three FLNG facilities measuring 488-m-long and 78-m-wide were planned for Browse, each capable of producing 3.9 million tonnes/year of LNG and 17,000-22,000 b/d of condensate. Another scenario envisaged two FLNG vessels with one moved around on the three targeted fields.
The three fields in question-Brecknock, Torosa, and Calliance-are 425-km north of Broome and estimated to contain gross contingent resources of 15.4 tcf of dry gas and 453 million bbl of condensate. The FLNG vessels were to be based on Shell technology that is being pioneered for the nearby $6-billion, 3.6 million-tpy Prelude project. The Prelude FLNG vessel is due for completion later this year.
Swap deal to boost Statoil's stake in Lundin
Statoil ASA has agreed to divest its entire 15% interest in Edvard Grieg field on PL338 offshore Norway to Lundin Petroleum AB in exchange for an increased shareholding in Lundin.
Expected to close by the end of July, the deal also includes divestment of 9% interest in the Edvard Grieg oil pipeline and 6% interest in the Utsira High gas pipeline (OGJ Online, Nov. 6, 2015), and a $68-million cash payment to Lundin, which in turn will issue 27.6 million shares to Statoil.
Lundin also will transfer 2 million treasury shares and issue an additional 1.74 million shares to Statoil in exchange for a cash consideration based on the market value of the shares.
Following completion of the deal, Statoil will own 68.4 million shares, or 20.1% of all shares, of Lundin. The swap, initiated by Lundin, is effective Jan. 1.
The two firms will continue to operate independently and act as separate entities in all licenses on the Norwegian Continental Shelf. Statoil says the deal strengthens its indirect exposure to core field development projects and growth assets on the NCS, including its operated Johan Sverdrup field.
As a consequence of the deal, Statoil will equity account its stake in Lundin, resulting in an increase in Statoil's reserves and production. Statoil has no plan to further increase its shareholding in Lundin.
Edvard Grieg field was discovered by Lundin Norway in 2007 and started production late last year (OGJ Online, Nov. 30, 2015).