UPSTREAM NEWS

BP makes Trinidad gas discoveries

BP Trinidad & Tobago (bpTT) today announced that it has made two significant gas discoveries with the Savannah and Macadamia exploration wells, offshore Trinidad. The results of these wells have unlocked approximately 2 trillion cubic feet (tcf) of gas in place to underpin new developments in these areas.

The Savannah exploration well was drilled into an untested fault block east of the Juniper field in water depths of over 500 feet, approximately 80 kilometers off the south-east coast of Trinidad. The well was drilled using a semi-submersible rig and penetrated hydrocarbon-bearing reservoirs in two main intervals with approximately 650 feet net pay. Based on the Savannah well, bpTT expects to develop these reservoirs via future tieback to the Juniper platform that is due to come online mid-2017.

The Macadamia well was drilled to test exploration and appraisal segments below the existing SEQB discovery which sits 10 kilometers south of the producing Cashima field. The well penetrated hydrocarbon-bearing reservoirs in seven intervals with approximately 600 feet net pay. Combined with the shallow SEQB gas reservoirs, the Macadamia discovery is expected to support a new platform within the post-2020 timeframe. BP Trinidad and Tobago has a 100% working in terest in Savannah and Macadamia.

Additionally, BP has sanctioned the Angelin offshore gas project in Trinidad. The project will feature the construction of a new platform 60 kilometers off the south-east coast of Trinidad in water-depth of approximately 65 meters.

The development will include four wells and will have a production capacity of approximately 600 million standard cubic feet of gas a day. Gas from Angelin will flow to the Serrette platform hub via a new 21 kilometer pipeline.

Drilling is due to begin in Q3 2018 and first gas from the facility is expected in 1Q 2019.

In a note following the news June 2 and noting the steady decline in BP's production levels in Trinidad in recent years, RBC Capital Markets said the "sanctioning of Angelin and the new discovery provide a pipeline of resources to help stem ongoing decline rates, which in addition to the start-up of Juniper later this year should help maintain production levels in this important country for BP (9% of group volumes)."

ExxonMobil acquires exploration acreage in Equatorial Guinea

Exxon Mobil Corp.'s wholly-owned affiliate, Exploration and Production Equatorial Guinea (Deepwater) Ltd., has signed a production sharing contract with the government of Equatorial Guinea for a deepwater block located 36 miles west of Malabo.

Deepwater block EG-11 measures about 307,000 acres and is adjacent to the Zafiro field located in Block B.

Following ratification of the contract by the government, ExxonMobil will carry out the work program as operator with an 80% working interest. GEPetrol holds a 20% working interest.

The contract includes a commitment to acquire new and reprocess existing 3-D seismic data. ExxonMobil will also work with the government of Equatorial Guinea to further develop the national workforce.

Mobil Equatorial Guinea Inc. operates the Zafiro field with 71.25% interest. GEPetrol has 23.75% interest and Equatorial Guinea has 5%. ExxonMobil Exploration and Production Equatorial Guinea (Offshore) Ltd. holds an 80% interest in block EG-06, which is adjacent to block EG-11.

East Daley: US natural gas supply far outpaces demand signaling major price correction

East Daley Capital Advisors Inc., an energy assets research firm, released a new report signaling the need for a major correction to US natural gas prices due to prolific production expectations from the Marcellus and Utica shale formations in the Northeast, which is now clashing with growth expectations in the Permian region in the Midcontinent. The newly released Part Two of the report, "Righting A Wrong: The Marcellus/Utica Balanced on a Knife's Edge," dissects the interconnection between energy market fundamentals and a company's financial performance to create a unique and comprehensive market outlook.

"Given the current forward curve, US natural gas supply and demand are extremely unbalanced, with total US supply outpacing demand by a staggering 11 Bcf/d by the end of 2019," said Justin Carlson, VP and managing director, research at East Daley Capital. "This signals a necessary price correction to incentivize incremental natural gas demand to help absorb the new production, much of which is expected to be produced in the Northeast and the Permian."

Part One of this report focuses on growth limitations in Northeast Marcellus. Part Two of this report analyzes southwest Marcellus and Utica as well the implications on the rest of the country due to production growth in the Northeast. Producer guidance in the Northeast suggests production will grow by 14.5 Bcf/d by 2019. However, the Marcellus and Utica are not without competition as East Daley expects fundamentals will slash northeast growth to 11 Bcf/d as natural gas prices adjust to accommodate surging associated gas production in the Permian.

"Basins like the Rockies, Haynesville and the Fayetteville need to pay close attention to what happens in the Northeast as those tier 2 and tier 3 basins are facing an uphill battle for market share and will most likely need to reduce their growth and earnings expectations," said Carlson. "The US natural gas market is entering into an intense era of gas-on-gas competition where only the best positioned will survive."

Key findings from Part Two (released June 2017) include:

• Given the current forward curve, US natural gas supply and demand is unbalanced, with total US supply outpacing demand by a staggering 11 Bcf/d by 4Q19. This signals a natural gas price correction to incentivize 4 Bcf/d of new demand and rationalize 7 Bcf/d of supply.
• Rationalization of supply will reduce growth expectations from Tier 2 and 3 basins, impacting interests in E&P companies and midstream assets without MVC's.
• Producer guidance in the Northeast suggests production will grow by 14.5 Bcf/d by 2019. East Daley expects fundamentals will slash Northeast growth to 11 Bcf/d as natural gas prices adjust to accommodate surging production growth in the Permian.
• Over $2.5 billion in contractual capacity commitments by producers to long-haul pipelines creates a significant incentive to produce for cash flow generation to cover those commitments.
• To meet these financial commitments, producers will only need to increase rig count by 8 in the Southwest Marcellus/Utica and by 10 in the Northeast Marcellus.
• Heavy reliance on LNG and LPG exports from substantial single sources of demand creates variable risk for supply should a project get canceled or have operational downtime.

Key findings from Part One (released May 2017) include:

• Expansions out of northeast Pennsylvania (NE PA) will result in $1.9 billion in EBITDA split almost evenly between midstream gathering and long-haul transportation.
• Higher-risk long-haul transport projects account for $182 million in transportation EBITDA but $254 million in midstream gathering EBITDA.
• Productive capacity for producers in NE PA is limited to 14.2 Bcf/d, 5.2 Bcf/d higher than current production levels.
• Cabot, Chief, Seneca and Shell will all see over 100% increases in production growth.
• Williams Partners (WPZ) will realize an upside of $658 million from NE PA, driven by production linked through their gathering systems to new long-haul expansions.
• ETP's NE PA gathering system will almost double from 16% to 28% of midstream segment EBITDA.

Majors start shaping strategies to capture a piece of the renewables action

Renewable energy sources are set to radically reshape global energy markets. For the Majors, this poses a threat to legacy oil and gas operations, but is also an opportunity to diversify and future-proof portfolios. A new report by Wood Mackenzie takes a closer look at the value proposition in wind and solar and the pace of the shift towards renewables out to 2035.

"The growth opportunity in renewables cannot be ignored," said Tom Ellacott, senior vice president, research, corporate analysis. "We forecast average annual growth rates of 6% for wind and 11% for solar over the next 20 years.

"Renewables will satisfy only 1% of the world's energy needs in 2017, but will have captured a much bigger slice of the global energy market by the middle of the next decade, as oil and gas demand growth."

Ellacott adds the value proposition is competitive versus some upstream investments. Returns rank favorably with many of the Majors' pre-sanction long-life developments, the most comparable upstream asset class. The long-life nature of wind and solar projects and stable cash flow visibility could also provide much-needed support for dividends.

The European Majors are leading the way in shaping strategies to establish a presence in this fast-growing market. Offshore wind may be the most attractive route to organic growth in the near term. It offers scale and scalability on a par with upstream mega-projects. Solar is more fragmented and competitive, but Total has used M&A to establish early mover advantage.

Wood Mackenzie expects capital to increasingly be diverted from upstream to build positions in wind and solar. Renewables could account for over one fifth of total capital allocation for the most active players post-2030. But wind and solar on their own are not going to transform growth prospects for the peer group as a whole.

"The scale of the opportunity is simply not there on our forecasts for solar and wind, at least not in the next 20 years," said Ellacott. "We estimate spend of US$350 billion on wind and solar out to 2035 is needed for the Majors to replicate the 12% market share they hold in oil and gas. But even this 'bull' scenario would lift renewables to just 6.5% of the Majors' production in 20 years' time."

Wind and solar are increasingly important strategic growth themes that the Majors cannot afford to ignore as they plan for 2035 and beyond. Companies are only just starting to sow the seeds for the radical changes that lie ahead. The Majors can bring their expertise in the energy value chain to build optionality and portfolio balance which will help hedge against any future erosion of the upstream value proposition and the anticipated progressive hardening of investor sentiment towards carbon.

EP Energy, Tesoro form Uinta Basin drilling jV

EP Energy Corp. and Tesoro Corp. formed a drilling joint venture, through respective subsidiaries, to fund oil and natural gas development in EP Energy's Altamont program located in the Uinta Basin of Utah. EP Energy and Tesoro signed a multi-year crude oil supply agreement for yellow and black waxy crude oil to supply Tesoro's Salt Lake City Refinery. The 60 well program will see Tesoro provide a capital carry in exchange for 50% of EP Energy's working interest in JV wells. Tesoro to purchase all oil production from the JV wells. EPE's net share of capital is expected to be $64 million and EPE will retain operational control of the JV assets. Under the supply agreement, Tesoro will purchase all of the oil produced through the drilling JV, along with additional waxy crude oil produced by EP Energy in the Uinta Basin. This oil will provide assured supply of local crude oil for Tesoro's Salt Lake City Refinery. EP Energy's average working interest in the joint venture wells is currently approximately 80%.