GENERAL INTEREST — Quick Takes
Proposed oil tax's revision would cost $8 billion
The additional 25¢/bbl in the Obama administration's proposed crude oil tax in its fiscal 2017 federal budget request would raise its costs over the next decade to $319 billion, a new Congressional Research Analysis found.
"This mathematical sleight of hand may look innocent, but that additional quarter actually raises the cost of the tax or 'fee' by nearly $8 billion," US Senate Energy and Natural Resources Committee Chair Lisa Murkowski (R-Alas.) said on Feb. 23 as she released the new analysis.
"Far from a rounding error, this increase would only put an additional burden on America's oil producers, which dampens our domestic energy production," she maintained.
The White House initially proposed a $10/bbl tax on crude oil to help pay for creation of a 21st Century Clean Energy Transportation System (OGJ Online, Feb. 4, 2016). That amount represented the average cost the White House Council of Economic Advisors calculated for the first 5 years as the levy would be phased in, CRS's new report said.
An earlier CRS analysis of the proposal found that the tax likely would result in lower general economic growth and higher costs for consumers, Murkowski said. The administration raised the amount to $10.25 bbl when it released its proposed federal budget for fiscal 2017 on Feb. 9. The proposed tax's details remain ambiguous, the senator said.
IHS: North American gas resource expanding
The North American natural gas resource continues to expand as breakeven development costs fall, reports IHS.
A new IHS study estimates that 1.4 quadrillion cu ft of gas in the US Lower 48 and Canada can be produced at a current, break-even Henry Hub gas price of $4/MMbtu or below. That's 66% more than the firm estimated in a study published in 2010. About 800 tcf can be produced at a current break-even price of $3/MMbtu or less, the new study finds.
New discoveries, recent reductions in drilling and completion costs, and "major gains" in productivity are the main reasons for the expansion of potential gas supply.
Key factors in these trends, the study says, are improved understanding of subsurface geology, greater use of technology, development of specialized fracturing techniques, and emergence of new plays such as the Utica shale.
Also contributing to the gas-resource expansion is the addition to the resource base of associated gas in emerging oil-shale plays as development methods first used for gas in shale spread to oil. IHS estimates the gas resource associated with Bakken, Eagle Ford, Permian basin, and other shale oil plays at 250 tcf.
NARUC resolution backs carbon capture for EOR
The National Association of Regulatory Utility Commissioners (NARUC) approved a resolution calling for capturing more carbon emissions at power plants for enhanced oil recovery (EOR).
The Feb. 17 action came after NARUC's Energy Resources and the Environment Committee passed Kentucky Public Service Commission Chairman James W. Gardner's resolution a day earlier during NARUC's 2016 Winter Meeting in Washington, DC.
It supports states' efforts to develop financing and other policies encouraging cost-effective use of CO2 from power plants for EOR; and urges Congress and the Obama administration to support legislation and budget measures that provide assistance to development and deployment of cost-effective carbon capture/EOR technology.
Doing so would increase national energy security, reduce US dependence on unstable overseas crude oil suppliers, and create high-quality jobs, the resolution said.
"Bipartisan legislation has been introduced previously in Congress to reform and provide for additional tax credits for CO2 capture for use in EOR," it noted. "These credits would pay for themselves over time through increased tax revenue due to increased oil production, without even considering the other job and economic benefits of EOR."
Gardner said, "This resolution underscores the need for the federal government to recognize the benefits of carbon capture for use in [EOR] and its essential role in enabling long-term, continued use of coal in an environmentally sound manner."
The National Enhanced Oil Recovery Initiative (NEORI) applauded NARUC's action, which it said was the third by a major group of state officials. Comparable resolutions were approved by the Western Governors Association in June 2015 and governors and state legislators on the Southern States Energy Board in September, NEORI said.
OMV focuses on 'highly profitable barrels'
OMV AG will deemphasize growth of oil and gas production under a new strategy that safeguards cash flow, focuses a restructured downstream oil business on utilization efficiency, and restructures downstream gas operations.
The Austrian company described its strategic changes while reporting a €1.1-billion loss attributable to shareholders for 2015 after a €278-million profit last year.
"The strategy of ramping up production volume at any price no longer holds," said Chief Executive Officer Rainer Seele. "We are focusing on highly profitable barrels. What this means is that profitability has priority over production growth."
The company plans to invest €2.4 billion in 2016, down 40% from 2014, the most recent year of elevated oil prices.
Under the new strategy, the company expects annual spending on exploration and appraisal to fall to €300 million by 2017 from €700 million in 2014.
In addition to slashing spending, it is selling nonstrategic assets. "The goal of all of these measures is to generate a broadly neutral free cash flow after dividends," the company said.
Until 2020, OMV will dedicate 90-95% of upstream investment to maintaining production at 300,000 boe/d. Other investment will target fourth and fifth phases of the Achimov development in Urengoy oil, gas, and condensate field in Russia (OGJ Online, Nov. 9, 2015).
OMV operates more than 70% of its producing interests. The company identifies Austria and Romania, the North Sea, the Middle East, and Africa as "core regions."
Its main "development regions" are Russia, the United Arab Emirates, and Iran.
With restructuring complete, OMV's downstream oil business will be "a cash generator," the company said. "The focus is on optimal capacity utilization of the refineries."
Restructuring of OMV's downstream gas business includes takeover of EconGas, a distribution joint venture and business-to-business gas marketer in which the company now holds a 64.25% interest, and its commitment to the Nord Stream 2 project (OGJ Online, Aug. 6, 2015).
First Oil's UK North Sea interests sold
UK North Sea interests of privately held First Oil Group PLC, Aberdeen, are being sold as the company moves into joint administration by KPMG LLP.
Zennor Petroleum Ltd. conditionally agreed to buy from First Oil Expro Ltd., part of First Oil Group, subsidiaries First Oil & Gas Ltd. (FOGL) and Antrim Resources (NI) Ltd.
The subsidiaries hold interests in Mungo and Monan, Bacchus, Cormorant East, and Causeway oil fields. The FOGL and Antrium units remain outside administration and will become wholly owned by Zennor.
Zennor's wholly owned Zennor North Sea Ltd. entered a separate purchase agreement to acquire First Oil's remaining interest in Cormorant East field and in undeveloped discoveries designated Glenn and Platypus.
Before KPMG administration began, FOGL sold its 15% interest in Kraken and Kraken North oil fields to the other interest owners, operator EnQuest PLC and Cairn Energy PLC.
EnQuest acquired 10.5%, raising its interest to 70.5%. With the acquisition of 4.5%, Cairn's interest increases to 29.5%.
The Kraken fields, in 110 m of water 350 km northeast of Aberdeen, are being developed for production via a floating production, storage, and offloading vessel with 25 development wells. EnQuest expects production to begin in first-half 2017.
KPMG said discussions are under way for disposition of First Oil's remaining assets.
Exploration & Development — Quick Takes
ExxonMobil replaced just 67% of output in 2015
ExxonMobil Corp. added 1 billion boe of proved oil and gas reserves in 2015, replacing just 67% of production during the year compared with 115% over the past 10 years.
In 2014, the firm replaced 104% of its production by adding proved oil and gas reserves totaling 1.5 billion boe.
The 2015 total includes a 219% replacement ratio for crude oil and other liquids.
However, proved reserves of natural gas were reduced by 834 million boe primarily in the US, reflecting the change in gas prices. The company expects this gas to be developed and booked as proved reserves in the future.
At yearend, ExxonMobil's proved reserves totaled 24.8 billion boe. Liquids represented 59% of proved reserves, up from 54% in 2014. ExxonMobil's reserves life at current production rates is 16 years. Reserves during the year were added in Abu Dhabi, Canada, Kazakhstan, and Angola. Liquid additions totaled 1.9 billion bbl.
ExxonMobil added 1.4 billion boe to its resource base through by-the-bit exploration discoveries, undeveloped resource additions, and strategic acquisitions.
The firm's exploration activity in 2015 included the Liza oil discovery offshore Guyana (OGJ Online, May 20, 2015), and additional discoveries in Iraq, Australia, Romania, and Nigeria. Strategic unconventional resource additions were made in the Permian basin, Canada, and Argentina.
Overall, the company's resource base totaled more than 91 billion boe at yearend 2015, taking into account field revisions, production, and asset sales. The resource base includes proved reserves, plus other discovered resources that are expected to be ultimately recovered.
Egypt's Zohr prospect could see first gas by 2017
A development plan approved by the Egyptian Ministry of Petroleum for the Zohr development in the Shorouk concession off Egypt could lead to natural gas production by yearend 2017.
Egyptian Natural Gas Holding Co. (Egas) has granted Eni SPA's development plan, pending contractual framework definition. The Zohr prospect was discovered in 2015, and Eni expects to reach about 75 million standard cu m/day of gas by 2019, the company said (OGJ Online, Sep. 7, 2015). The first appraisal well, Zohr-2, is currently being drilled, Eni said.
Cyprus planning third licensing round
The government of Cyprus plans a third round of offshore oil and gas licensing, according to press reports.
Spokesman Nicos Christodoulides was reported to have said preparations will start soon. He gave no further details.
Turkey, which dominates northern Cyprus, objects to the earlier licensing rounds, claiming Turkish Cypriots were excluded from decision-making.
A group led by Noble Energy Inc. in 2011 discovered Aphrodite natural gas field in deepwater Block 12, awarded in the first licensing round and on trend with the giant Leviathan and Tamar deepwater gas discoveries in Israeli waters (OGJ Online, Nov. 23, 2015).
In a second licensing round after the Block 12 discovery, the Greek Cypriot government awarded two blocks to Total and three blocks to a combine of Eni and Korean Gas Corp.
Last month, the Ministry of Energy, Commerce, Industry, and Tourism granted Eni-Kogas a 2-year extension of the initial exploration phase of their licenses.
Airborne gravity survey slated for offshore Mexico
The Comision Nacional de Hidrocarburos (CNH) has authorized French geophysical services company CGG to conduct a multiclient airborne gravity and magnetic survey off Mexico in the Gulf of Mexico. The acquisition will include about 200,000 km of 2D seismic over six areas across the southern gulf.
Data acquisition will start in March and is expected to take a year to complete. The survey will cover several prolific areas such as the Perdido fold belt and the more-mature near-shore heavy oil belt.
Last year CNH approved the acquisition of multibeam, coring, geochemical analysis data over 600,000 sq km in Mexican waters (OGJ Online, Aug. 24, 2015). That work was conducted by TGS-NOPEC Geophysical Co.
Drilling & Production — Quick Takes
Zora gas field flowing off Sharjah, Ajman
Dana Gas PJSC, Sharjah, reports Zora gas field offshore Sharjah and Ajman has started production with optimization under way to boost flow to a planned 40 MMcfd (OGJ Online, Nov. 19, 2013).
The field produces from two wells drilled laterally into a Lower Cretaceous Thamama reservoir straddling the Sharjah-Ajman offshore boundary. The gas flows by a 35-km pipeline from a platform in 24 m of water to an onshore processing plant in the Hamriyah Free Zone in Sharjah.
Dana Gas, operator with 100% interest, describes the field as a tilted fault block structure with fault and dip closure of 25 sq km.
Kosmos Energy updates Jubilee field operations
Kosmos Energy Ltd., Dallas, reported that it was informed by Tullow Oil PLC, operator of the Jubilee unit off Ghana, of a change to operating procedures on the Jubilee field floating production, storage, and offloading vessel. Oil production and gas exports from the area are continuing as normal, however.
"Following a recent inspection of the turret area of the Jubilee FPSO by Sofec Inc., the original turret manufacturer, a potential issue was identified with the turret bearing," Kosmos said. Additional operating procedures to monitor the turret bearing and reduce the degree of rotation of the vessel are being put into place as a precautionary measure, Kosmos said.
Sofec will now undertake further offshore examinations and Tullow will work with the engineering firm to determine what further measures will be required.
Gas exports to the Ghana gas plant at Atuabo were most recently suspended July 3, 2015, due to technical issues with gas compression systems on the Kwame Nkrumah FPSO (OGJ Online, July 20, 2015). Tullow reported in August that gas exports from the field had resumed and oil production had returned to previous rates (OGJ Online, Aug. 17, 2015). During first-half 2015, oil production from Jubilee averaged 105,000 b/d.
Subcontract let for Kaombo oil development off Angola
Work continues on the Kaombo oil development offshore Angola. Under a subcontract let by Technip SA to Fugro NV, the Dutch engineering firm will provide offshore deepwater survey and positioning services to a total of seven installation vessels and construction support vessels.
Kaombo, operated by Total E&P Angola, lies on Block 32 in 1,400-2,000 m of water about 260 km offshore Luanda (OGJ Online, Apr. 16, 2014). It includes six fields that will be tied back to two converted floating production, storage, and offloading vessels.
The contract starts in this year's second half and is slated to continue until early 2018.
PROCESSING — Quick Takes
Phillips 66 buys interest in Sweeny NGL fractionator
Phillips 66 Partners LP has agreed to acquire 25% controlling interest in Phillips 66 Sweeny Frac LLC, owner of the newly constructed Sweeny Fractionator One and Clemens Caverns storage facility, from Phillips 66 Co. for $236 million. The deal is expected to close in early March.
Sweeny Fractionator One is a 100,000-b/d NGL fractionator near Phillips 66's 247,000-b/d Sweeny refinery in Old Ocean, Tex. Startup of the unit was reported in December (OGJ Online, Dec. 8, 2015).
The Clemens Caverns storage facility is 15 miles southeast of the Sweeny refinery, and includes five newly developed caverns that will have storage capacity of 7.5 million bbl of Y-grade NGL, propane, and butane, with the capability for future capacity expansion.
"This acquisition expands and diversifies our fee-based portfolio into natural gas liquids fractionation and storage," explained Greg Garland, Phillips 66 Partners chairman and chief executive officer.
In connection with the deal, Phillips 66 will enter into fractionation and storage agreements, each with a 10-year term, that include a minimum fractionation volume commitment for Sweeny Fractionator One and minimum storage commitments at the Clemens Caverns storage facility.
Calumet wraps Montana refinery expansion
Calumet Specialty Products Partners LP, Indianapolis, has completed a long-planned project to more than double crude processing capacity at subsidiary Calumet Montana Refining LLC's refinery in Great Falls, Mont.
The refinery's 25,000-b/d crude unit is now on stream and scheduled to reach full operating capacity by the end of March, Calumet Chief Executive Officer Tim Go told investors in the company's most recent earnings report.
Initially intended to lift crude processing at the refinery to 20,000 b/d from its original 10,000-b/d capacity (OGJ Online, Feb. 21, 2014), the $400-million expansion also was to include installation of a 25,000-b/d mild hydrocracker (MHC) to convert gas oil to higher-value distillates, a hydrogen plant to support the MHC, and a treatment unit to handle increased fuel gas production from the MHC.
Alongside expanding overall capacity, the crude unit is designed to process heavy sour crudes to enable Calumet to benefit from nearby access to cost-advantaged heavy Canadian crudes (OGJ Online, May 16, 2014).
During this year's first quarter, the company already has taken steps to ramp up its refineries intake of Canadian grades, Go said.
While Calumet historically has processed 20,000-25,000 b/d of heavy Canadian crude at its refineries-roughly one quarter of its overall crude slate-the company plans to boost processing rates of less-expensive Canadian feedstock to 40,000-45,000 b/d by yearend, and longer term to as much as 70,000 b/d, Go said.
At subsidiary Calumet Lubricants Co.'s 17,500-b/d San Antonio refinery, Calumet also reported the completion of a $65-million project designed to convert a portion of the refinery's ultralow-sulfur diesel and jet fuel production into about 3,000 b/d of higher-margin solvents to help meet customer requirements for low-aromatic content.
TRANSPORTATION — Quick Takes
PHMSA releases first report on Plains line failure
External corrosion under the insulation caused the May 15, 2015, rupture of a Plains All American crude oil pipeline in California, the US Pipeline and Hazardous Materials Safety Administration said in a preliminary report from its ongoing investigation of the incident.
The rupture in Santa Barbara County allowed more than 500 bbl of crude to leak into a nearby state park and ultimately the Pacific Ocean (OGJ Online, May 20, 2015). PHMSA still is investigating the incident and plans to issue a final report later this year, the US Department of Transportation agency said as it released the initial report on Feb. 17.
It said the report includes details from the required metallurgical analysis of the failed pipeline section following the event, and a third-party review of in-line inspection (ILI) results for Lines 901 and 903. Plains conducted ILI surveys on Line 901 to assess the integrity of the pipeline in 2007, 2012, and 2015, PHMSA noted.
PHMSA's final incident investigation report will incorporate all aspects of the events leading up to the release and all contributory causes, including details as to the specific cause of the external corrosion and information about the operator's adherence to federal regulations regarding the operation of Lines 901 and 903, PHMSA said.
It said that it has required the pipeline's operator, Plains Pipeline LP in Houston, to take a number of actions to restore and rehabilitate the safety and integrity of their pipelines.
PHMSA said that its review of the Plains pipeline's internal inspection results, which the operator conducted before the failure, discovered instances where the inspection tool miscalculated the degree of corrosion occurring in specific portions of Line 901 and Line 903.
As a result, PHMSA ordered Plains to remove all crude oil from Line 903 to reduce the risk of corrosion and any impact the pipeline's safety and integrity, the agency said.
Sunoco lets contract for Mariner East 2 NGL pipeline
Sunoco Logistics Partners LP, Philadelphia, has let a construction management contract to Fluor Corp., Irving, Tex., for the Mariner East 2 natural gas liquids pipeline project.
Mariner East 2 is the second phase of the company's broader plan to transport 275,000 b/d of various NGLs (propane, butane, and ethane) from processing and fractionation complexes in the Marcellus and Utica shale areas in western Pennsylvania, West Virginia, and eastern Ohio to Sunoco Logistics' 800-acre Marcus Hook Industrial Complex (MHIC) in southeastern Pennsylvania.
Fluor will manage the construction of new terminal facilities to store, chill, process, and distribute the NGLs at the complex.
The contract's value was undisclosed.
In late 2014, Sunoco Logistics reported receiving sufficient binding commitments from shippers to move ahead with the $2.5-billion investment in the Mariner East 2 NGL pipeline project (OGJ Online, Nov. 7, 2014).