GENERAL INTEREST — Quick Takes
North American producers’ hedge cover to fall
Exposure of North American oil and gas producers to low oil prices will increase in 2016, according to IHS.
Hedging protection in place for 48 exploration and production companies will fall to 11% of total production volumes next year from 28% for the remainder of 2015, the firm says in a new study.
The implied weighted-average hedge prices for the group next year are $69.04/bbl for oil and $3.83/Mcf of natural gas.
Midsize E&P companies in the IHS group have the largest share of total production hedged next year: 26%. The group has 36% of oil production hedged at an implied weighted-average price of $69.34/bbl and 18% of gas production at $3.67/Mcf.
Large E&P companies have 4% of oil production hedged at $63/bbl and 10% of gas production at $3.87/Mcf. The hedge share of total production for this group is 6%.
Small companies, with 25% of total production hedged, have 27% of oil production hedged at $76.89/bbl and 28% of gas production hedged at $3.86/Mcf.
"For the smaller companies, the combination of less hedging and lower oil prices does not paint a pretty picture for 2016," said Paul O’Donnell, principal equity analyst at IHS Energy and report author. "Companies that missed the opportunity to lock in relatively higher oil prices during the second quarter of 2015 will face pressure to curtail drilling activity and [capital expenditures] in order to avoid further balance sheet deterioration."
IHS expects capital spending for the group of companies to drop to $45 billion in this year’s second half from about $60 billion in the first half.
Because costs are falling, IHS believes E&P companies can earn rates of return with the crude price at $60/bbl similar to what they formerly earned at $90/bbl.
COS to review Suncor’s unsolicited takeover bid
The board of Canadian Oil Sand Ltd. (COS) reported it will review the unsolicited takeover offer made Oct. 5 by Suncor Energy Inc., Calgary. Suncor’s offer to acquire all the outstanding shares of COS is valued at $4.3 billion (Can.).
Under the offer’s terms, each COSL shareholder would receive 0.25 of a share of Suncor for every share of COS, Suncor reported.
COS urged its shareholders "not to take any action or make any decision with regard to the Suncor offer until the board has had an opportunity to fully review the Suncor offer and to make a recommendation as to its merits."
Suncor Pres. and CEO Steve Williams called the offer a "financially compelling opportunity" for COS shareholders. COS holds 36.74% interest in the Syncrude project, the largest producer of light, sweet synthetic oil from Canada’s oil sands.
Freeport-McMoRan considers oil, gas spinoff
Freeport-McMoRan Inc., Phoenix, is reviewing "strategic alternatives" for its oil and gas business, including its possible spinoff to shareholders, joint venture arrangements, and further spending reductions.
The company says the previously announced potential public offering of minority interest in Freeport-McMoRan Oil & Gas LLC remains an alternative for future consideration, the timing of which is subject to market conditions.
The business has assets in the deepwater Gulf of Mexico, including "substantial underutilized" deepwater infrastructure; onshore and offshore California; in the Haynesville shale; and in the Inboard Lower Tertiary-Cretaceous natural gas trend onshore South Louisiana.
Freeport-McMoRan Oil & Gas last week reported that it expects to start oil production in 2017 from its Horn Mountain Deep well, which will be tied back to the Horn Mountain truss spar in 5,500 ft of water offshore Louisiana (OGJ Online, Sept. 29, 2015).
Petrobras cuts capital budget for 2015-16
Petroleo Brasileiro SA (Petrobras) reported further cuts to its capital budget, reducing planned spending in 2015 by $3 billion to $25 billion and in 2016 by $8 billion to $19 billion. It cited low crude oil prices and unfavorable exchange rates.
Petrobras maintains a divestment target of $15.1 billion for 2015-16, with $700 million in 2015 and $14.4 billion in 2016. Average oil production targets are unchanged at 2.125 million b/d in 2015 and 2.185 million b/d in 2016.
"As recently as 2 years ago, capital spending was running at over $40 billion," Financial services firm Raymond James & Associates Inc. said in an Oct. 6 energy update. "To be sure, the Brazilian real’s depreciation [down 32% year-to-date] plays a key role here, so in local currency terms the change is much smaller than in dollar terms," RJA said.
The analyst said, however, "All in all, we are surprised by the magnitude of these latest cuts, even though the June business plan already signaled prolonged austerity for the company."
Petrobras in August reported first-half net income of $1.69 billion, down 43% year-over-year (OGJ Online, Aug. 10, 2015). Its second-quarter net income plunged 90% year-over-year to $154 million.
Exploration & Development — Quick Takes
Ghana block study: 500 million bbl in place
A block with three legacy oil fields in shallow water offshore Ghana holds 500 million bbl of oil and 282 bcf of natural gas in place, according to an independent assessment reported by Erin Energy Corp., Houston.
The assessment covered the 373,000-acre Expanded Shallow Water Tano (ESWT) block, for which Erin signed a joint operating agreement for a 2-year initial exploration period last January. Erin subsidiary Camac Energy Ghana Ltd. is operator.
The block encompasses South Tano field, discovered in 1978 by Phillips Petroleum; North Tano field, discovered in 1980 by Phillips; and West Tano field, discovered in 2000 by Dana Petroleum. The fields are 9-21 miles offshore in 180-380 ft of water.
The ESWT block is north of giant Jubilee oil and gas field operated by Tullow Oil PLC (OGJ Online, Aug. 17, 2015).
The ESWT assessment considered results of 14 wells drilled by prior operators, many of which were flow-tested with oil and gas to surface. Test rates ranged from 600 b/d to 2,047 b/d of 15°-32° gravity oil. Erin said tests established a maximum gas flow rate of about 13 MMcfd.
Erin said it and partners are considering development options. A declaration of commerciality, it said, "is expected within the next few months."
Development drilling could begin as soon as 2017.
Block interests are Erin and Ultramar Energy Resources Ltd., 30% each; Ghana National Petroleum Corp., 25%; and Base Energy Ghana Ltd., 15%.
AWE-led venture tests gas in Perth basin
The AWE Ltd.-operated joint venture with Origin Energy Ltd. has tested a significant flow of natural gas from its Waitsia-1 well in production licenses L1/L2 in the north Perth basin onshore Western Australia.
The well flowed at a rate of 24.7 MMcfd of gas from the High Cliff Sandstone, the rate only being constrained by tubing size.
AWE says the flow is twice that of the nearby Senecio-3 well and is only from the first zone of interest in the well. The Kingia Sandstone deep gas play is still to be tested.
The Waitsia tests are designed to determine well delivery rates from the two conventional gas reservoirs as well as to collect samples for analysis.
The High Cliff Sandstone is a 23.5-m thick interval in the well below 3,382 m.
Waitsia-1 will now be shut in to allow pressure build-up prior to a series of flow tests later this week through various choke settings, rates, and wellhead pressures.
A plug will then be set to isolate the lower interval prior to a similar test of the Kingia Sandstone. This reservoir tested at 12.3 MMcfd at Senecio-3.
AWE plans a rapid development of 9 months with a pipeline planned to connect Waistia-1 and Senecio-3 to the Xyris production facility near the Waitsia-2 well.
AWE and Origin each have 50% interest in the licenses.
Petrobras confirms extension of Carcara discovery
A third exploratory well drilled by Petroleo Brasileiro SA (Petrobras) in the Carcara area of the ultradeepwater Santos basin again confirmed the presence of good quality light oil of 31º gravity in presalt reservoirs.
Well 3-SPS-104DA, known as Carcara Northwest, lies 226 km from Sao Paulo state and 5½ km northwest of the original discovery well on Block BM-S-8 in 2,204 m of water.
Pressure data indicate the oil is part of the same accumulation as two other wells previously drilled in the area, confirming the westward extension of Well 4-SPS-86B (OGJ Online, May 29, 2015). Well 3-SPS-104DA encountered carbonate reservoirs with excellent features situated just below the salt layer at 5,870 m, finding a 318-m oil column with no water contact, Petrobras says.
Petrobras, which operates Carcara with 66% interest, will conduct formation tests through recently drilled Well 3-SPS-105 to determine the presalt reservoirs’ productivity.
Drilling & Production — Quick Takes
Production begins from Bonga Phase 3 off Nigeria
Shell Nigeria Exploration & Production Co. Ltd. (SNEPC) has started production offshore Nigeria from the Bonga Phase 3 project, an expansion of the Bonga Main development.
Peak production is expected at 50,000 boe/d. Resources will be transported through existing pipelines to the Bonga floating production, storage, and offloading facility, which can produce more than 200,000 b/d of oil and 150 MMscfd of gas.
Bonga field, which began producing oil and gas in 2005, was Nigeria’s first deepwater development in depths of more than 1,000 m (OGJ Online, Dec. 1, 2005). Shell last year started production from the first well at Bonga North West (OGJ Online, Aug. 6, 2014). Bonga has produced more than 600 million bbl of oil to date.
SNEPC operates the Bonga project as contractor with 55% interest under a production-sharing contract with Nigerian National Petroleum Co., which holds the lease for OML 118 where Bonga field lies. Partners are Esso E&P Nigeria Ltd. 20%, Total E&P Nigeria 12.5%, and Nigerian Agip Exploration 12.5%.
Shell lets subsea contract for Stones project
Shell Offshore Inc. has let a contract to Technip SA for development of subsea infrastructure for the Stones project in the Walker Ridge area of the US Gulf of Mexico.
Included in the service are two subsea production tiebacks to the floating production, storage, and offloading vessel (OGJ Online, July 23, 2013). The field lies in 2,930 m of water along the pipelay route.
The contract covers engineering of the required second pipeline end terminations (PLET); fabrication of the PLET and piles; and installation of the subsea production system, including associated project management, engineering, and stalk fabrication. The production system comprises dual 8-in. insulated flowlines with PLET involving a manifold and associated suction piles installed as part of the system.
Technip’s operating center in Houston will perform the overall project management. Flowlines will be welded at the company’s spoolbase in Mobile, Ala. The offshore installation is scheduled to be performed by the Deep Blue, Technip’s flagship vessel for deepwater pipelay.
Technip in 2013 received a contract from Shell that included installation of the Stones lateral gas pipeline (OGJ Online, Aug. 23, 2013).
Gazprom Neft says Badra oil output at 45,000 b/d
JSC Gazprom Neft says oil production from Badra field in Iraq has reached 45,000 b/d as a sixth well, the P-13, is producing 10,000 b/d (OGJ Online, July 23, 2015). Oil production was 17,000 b/d in early 2015.
Drilling continues at P-09, P-15, and P-12. These wells are expected to be brought on production in 2016.
Earlier this month, Gazprom Neft received its second allocation of oil as compensation for costs incurred in developing Badra in Wasit province in eastern Iraq. The first consignment was received in April.
PROCESSING — Quick Takes
NH court rules against ExxonMobil in MTBE appeal
The New Hampshire Supreme Court denied ExxonMobil Corp.’s appeal of a lower court’s $236 million award to the state in a lawsuit charging groundwater contamination from the company’s use of methyl tertiary butyl ether as a gasoline oxygenate additive in the 1980s.
The state’s highest court also determined in its Oct. 2 decision that New Hampshire is entitled to tens of millions of dollars in prejudgment interest in addition to $90 million that it previously received in settlements from several other gasoline suppliers who settled with the state prior to trial, Atty. Gen. Joseph A. Foster (D) said.
The court also ruled that the verdict money would not be subject to a trust, he added.
ExxonMobil immediately disagreed with the decision. "MTBE contamination has been found in New Hampshire because someone spilled gasoline in New Hampshire, not because it was added to gasoline in a refinery in another state," a spokesman said in a statement e-mailed to OGJ. "The state should have sued the parties responsible for spilling gasoline, not the refiners who were compelled by law to add oxygenates to gasoline."
The spokesman said, "MTBE contamination in New Hampshire is rapidly decreasing, and the state’s current regulatory system, in which responsible parties pay for cleaning up gasoline spills, is effective in ensuring safe drinking water. We made strong legal and factual arguments on appeal, and will consider appealing to the US Supreme Court."
Foster said the state government’s litigation spanned five attorneys general and four governors, included over 9 million pages of discovery, and culminated in a 3-month trial. The state, through the governor’s Office and the legislature, now will begin the process of determining how to use this money to best benefit New Hampshire’s citizens, he said.
"This is the most significant environmental victory in the state’s history," Foster maintained. "This historic decision sends a clear message that New Hampshire will not permit polluters to endanger the health of its citizens and destroy its natural resources."
Delek lets contract for Tyler refinery
Delek US Holdings Inc. has let a contract to ClearSign Combustion Corp., Seattle, to implement its Duplex combustion and emissions-control technology at the newly expanded 75,000-b/d refinery in Tyler, Tex.
The project, to be executed by JLCC Inc., Lindale, Tex., on behalf of ClearSign, includes the retrofitting of burners inside one of the refinery’s process heaters with the Duplex technology, which is intended to eliminate potential flame impingement on process tubes in an effort to improve Tyler’s utilization rates, reduce maintenance costs and downtime, and reduce emissions of nitrogen oxide, ClearSign said.
If this initial installation proves a viable solution for the Tyler plant, Delek has agreed to consider retrofitting the Duplex technology into other process heaters in its operations, according to ClearSign. A value of the contract was not disclosed.
Earlier this year, Delek wrapped a project at Tyler to expand the refinery’s crude processing capacity by 15,000 b/d, or 20%, from its previous processing capability of 60,000 b/d (OGJ Online, Mar. 26, 2015).
Completed during a 2-month planned maintenance turnaround, the expansion project involved modifications to the refinery’s atmospheric and vacuum distillation units, naphtha hydrotreater, diesel hydrotreater, and saturate gas unit, as well as a minor modification to the delayed coker’s fractionator (OGJ, Sept. 7, 2015, p. 104).
Completion of the Tyler plant’s February-March turnaround marked the end of a large-scale capital investment program in the company’s refining segment to increase crude flexibility and overall processing capacity of both of Delek’s US refineries.
Lukoil starts up cracker at Russian refinery
PJSC Lukoil has commissioned a second complex for catalytic cracking of vacuum gas oil at its 17 million-tonne/year Nizhny Novgorod refinery at Kstovo, Russia.
Startup of the unit, which is equipped with a processing capacity of 2 million tpy, will increase the refinery’s production of Euro-5 quality fuels by 1.1 million tpy from its current total production of 3 million tpy, Lukoil said.
The cracking complex also will nearly double production of propylene at the site to 300,000 tpy, the operator said.
The CCC-2 project, which began construction in 2010 following the launch of Nizhny Novgorod’s 2.6 million-tpy CCC-1 (OGJ Online, Sept. 19, 2012), required a total capital investment of $1 billion, Lukoil said.
TRANSPORTATION — Quick Takes
PHMSA fines ExxonMobil for 2013 Arkansas leak
The US Pipeline and Hazardous Materials Safety Administration (PHMSA) fined ExxonMobil Pipeline Co. more than $2.6 million in connection with the 2013 rupture causing a crude-oil leak from its Pegasus Pipeline near Mayflower, Ark. (OGJ Online, Apr. 1, 2013).
In its final administrative action on the matter, PHMSA said the line failed because the ExxonMobil Corp. subsidiary violated federal pipeline safety regulations for integrity management and operations and maintenance procedures.
"The failure investigation concluded that the cause of the incident was a result of time intensified defects of originally manufactured pipe," the US Department of Transportation agency said. About 3,190 bbl of oil spilled from the 853-mile, 20-in. line from Patoka, Ill., to Nederland, Tex., it said.
PHMSA approved ExxonMobil Pipeline’s request to return the pipeline’s southern segment to service in July 2014 at a reduced operating pressure. The line’s northern segment, which extends through Mayflower, remains out of service under PHMSA’s authority, PHMSA said.
ExxonMobil Pipeline and a second ExxonMobil subsidiary, Mobil Pipeline Co., agreed to pay $5 million to the federal government and the Arkansas state government earlier this year to settle charges stemming from the incident (OGJ Online, Apr. 22, 2015).
"ExxonMobil Pipeline has received and is evaluating its options with respect to PHMSA’s final order for the 2013 Mayflower incident," a spokesman said in response to OGJ’s inquiry.
Targa, Sanchez Energy form Eagle Ford gas JV
Targa Resources Partners LP and Sanchez Energy Corp. have agreed to form joint ventures that will construct a 200-MMcfd cryogenic natural gas processing plant in La Salle County, Tex., and 45 miles of high-pressure gathering pipelines that will connect Sanchez Energy’s Catarina gathering system to the plant.
Targa expects to contribute $125 million to the JVs while Sanchez Energy expects to contribute $115 million. Each company is slated to receive 50% ownership interest in the plant and the associated pipelines.
The La Salle County plant, whose capacity will be expandable to 260 MMcfd, will accommodate growing production from Sanchez Energy’s Eagle Ford shale acreage position in Dimmit, La Salle, and Webb counties in Texas and from other third-party producers.
Targa will manage construction and operations of the plant and gathering lines. The plant is expected to begin operations in early 2017. Targa will hold all the transportation capacity on the pipeline, and the gathering JV will receive fees for transportation.
Sanchez Energy has firm capacity for 125 MMcfd of plant processing and pipeline capacity for the first 5 years and has dedicated the Catarina acreage and all production developed during the 15-year term. The company has the option to deliver additional volumes and commit additional acreage to the new plant as production increases.
"The modern plant design is expected to deliver better liquids yields and lower processing fees, resulting in lower operating costs, higher net-backs, and greater price realization on our natural gas liquids revenue stream," said Sanchez Energy CEO Tony Sanchez III. "The joint ventures are expected to also improve our access to end markets, including the developing Mexico and global LNG markets, and provide opportunities to increase revenue through utilization of the new midstream system to transport and process third party volumes."
Sanchez Energy in late September agreed to sell certain pipeline, gathering, and compression assets on the western part of its Catarina asset to affiliate Sanchez Production Partners LP for $345 million (OGJ Online, Sept. 28, 2015). Sanchez Energy said proceeds from that sale would enable the company to pursue asset acquisitions, the acceleration of cost-efficient drilling and completion, and the strategic leasing of additional acreage in its core operational areas.
Targa earlier this year completed its $7.7-billion acquisitions of Atlas Pipeline Partners LP and Atlas Energy LP, which included Eagle Ford assets.
SandRidge to acquire West Texas gathering company
SandRidge Energy Inc., Oklahoma City, has agreed to acquire Pinon Gathering Co. LLC, Houston, from EIG Global Energy Partners for $48 million cash and $78 million of its 8.75% senior secured notes due 2020. The deal is expected to close in the fourth quarter.
Pinon Gathering owns 370 miles of gathering lines supporting natural gas and carbon dioxide production from the company’s Pinon field in West Texas.
As a result of the deal, SandRidge will eliminate minimum volume commitment payments of $40 million/year, forecast to continue until 2021, and additional contractual fees thereafter, as well as secure a strategic asset supporting its West Texas gas production.