Oilfield services recovery unlikely in 2016


Highlighting all of the top stories and what to look for in the week ahead, our 'week in brief' notes keep you informed on the North American Upstream sector, including the Lower 48, Gulf of Mexico, and Alaska.

23 October 2015

Oilfield services recovery unlikely in 2016

Although some smaller oilfield service players are operating at (or below) true variable cash breakevens, Schlumberger has cautioned analysts against using their failure as a basis for a bottom, since their equipment is likely to end up in the hands of larger players.

Indeed, the profitability of small companies shouldn’t be expected to define the bottom of this oil service cycle. The US market is currently operating below 50% of peak activity and may never be called upon to grow production at the same pace as it did from 2012 to 2014.

The market is sending signals to the oilfield service industry: scrap equipment or run it into the ground. Halliburton estimates 25% of pumping capacity has been cannibalised beyond recovery. 

We share Schlumberger's view that a strong activity recovery is unlikely in 2016 and broad-based US land service company pricing power is a 2017 event. Strategic considerations will keep major operators spending within cash flow, implying 2016 activity will be down year-on-year.

Halliburton, while expecting North America Q4 horizontal rig count to be down 15-20% sequentially from Q3, holds hope that drill-or-die operator activity could re-accelerate spend in early 2016.

What these two bellwethers do agree upon, however, is the role technology will play in making it through this down-cycle and thriving in the next upcycle. Halliburton claims that its new generation frac fleets save 25% in capital on location, 30% in onsite labour and 50% in ongoing maintenance cost.

Meanwhile, Schlumberger announced a 15-year licence with Energy Recovery for a technology that could significantly reduce the number of pumps needed on a frac job. This further drives the need for service companies to rationalize capacity, or they will face a delayed service pricing recovery.

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Oilfield Recovery

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16 October 2015

Encana sells Niobrara oil and gas assets for $900m

Encana is selling its 51,000-net acre position in the Denver-Julesburg (DJ) Basin to a new entity - 95% owned by the Canada Pension Plan Investment Board (CPPIB) and 5% owned by the Broe Group – as it strives for a healthier balance sheet and a liquids-weighted portfolio.

Encana DJ Basin Niobrara position

Assets with a diversified production mix in plays like the Niobrara provide an attractive opportunity to bet on a general price recovery without being too exposed to one particular commodity. For Encana, the deal underlines the company's strategy to reposition its asset base towards liquids-rich plays, mitigate near-term cash-flow pressures and deleverage its balance sheet.

We value the acquired assets at US$1.09 billion. The acreage is located in and around sub-plays with some of the most consistent, economic wells in the Niobrara, with breakevens below US$50/bbl WTI, offering upside opportunities through downspacing, multi-bench drilling, extended reach laterals (XRLs) and upsized completions.

Operators have identified a generally positive correlation between pounds per foot of proppant and increased production rates in the play. Encana tested as much as 1,500 pounds of proppant per lateral foot, while other operators like Anadarko experimented with concentrations in excess of 2,000 lbs/foot.

The application of technology has been, and will continue to be, critical in lowering costs and increasing reserves in the DJ Basin.

Read more in our report Encana sells DJ Basin assets to Canada Pension Plan Investment Board for US$900m.

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9 October 2015

US rig count to bottom next summer

With US horizontal oil rig count sitting at 487, we have readjusted our outlook to reflect a bottom of 392 rigs in June 2016 – a significant change from our previous forecast which anticipated a low of 488  in October 2015.

horizontal oil rig forecast

This change is driven by our expectation that, should oil prices remain flat until the end of this year, operators will make a meaningful capex cut in 2016 as they look to spend within their cash flows.

Oil production will feel the impact nine months later. We expect output to bottom at 6.6 million b/d in March 2017, down from 7.4 million b/d this year. Rig activity will hold flat next summer before back rigs are added in late Q3 2016 when our WTI price forecast surpasses $60 per barrel.

The dramatic reduction in rig activity is reflective of the percentage of production coming from top tier areas. In 2016, only 50% of rigs are needed to achieve 80% of the new production we see today.

Capex reductions in 2016 could also pave the way for a greater draw down of drilled but uncompleted wells in 2016. However, we note that this process is highly iterative and, should WTI react more strongly or sooner to evidence of US production declines, we may not see such a relatively severe rig count decline.

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2 October 2015

Will Shell's dry hole derail future Arctic interest?

On 28 September, Shell announced it will not pursue further exploration at the Burger field in the US Chukchi Sea. Although the company successfully drilled to a total depth of 2,070 metres (6,800 feet) and encountered oil and gas, it said the results were not sufficient to justify any further activity.

Arctic Ocean

This announcement ends a nine-year exploration programme that Shell pursued with a 100% working interest. After paying US$2.1 billion in signature bonuses in 2008, the company spent more than US$5 billion on the programme that resulted in just one tophole and one completed well.

This negative result underlines many of the challenges that operators face elsewhere in the Arctic, including environmental sensitivity and stringent safety regulations. The move also fits into a larger industry trend of pulling back from high-cost ultra frontier exploration to free up capital to focus on lower-risk exploration and appraisal.

The Bureau of Ocean Energy Management has scheduled lease sales in the Chukchi and Beaufort seas in 2016 and 2017 respectively. However, with Shell's results casting deep uncertainty over the viability of the US Arctic, we expect extremely low levels of participation and interest, with this decision potentially deferring all exploration in Alaska's federal waters.

Read more in our Inform, Shell to abandon US Arctic exploration efforts, September 2015. 

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24 September 2015

Eagle Ford acreage to swap hands for $118 million

Alta Mesa has announced its exit from the Eagle Ford with a sale to EnerVest for $118 million – EV’s second announced deal this month.

The acreage is located in and around Karnes County and operated primarily by Murphy Oil. We assume a 515 mboe type well in this project, one of Murphy’s most economic Lower 48 assets.

This sale is true to EnerVest’s strategy of buying mid-life assets and gives Alta Mesa additional capital to fund its drilling programme in the Mid-Continent STACK play where the company faces acreage expirations. It should put the proceeds to work quickly to hold acreage so watch for a rig and/or permit bounce. Alta Mesa is also hunting for acquisitions to expand – another option for reinvestment.

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03 September 2015
Premier Permian acreage holds its value

This week, acquisition and exploration company W&T Offshore announced that it would sell 25,800 net acres - primarily located in northwest Martin County in the Deep Basin sub-play of the Wolfcamp - to Ajax Resources for US$376 million.

On an adjusted basis, the agreement falls closely in line with our base case Wolfcamp Key Play valuation of US$12,600/acre. However, while the deal valuation appears strong at first glance, it falls more than 50% short of the valuations RSP Permian and LINN Energy put on deals in Martin and Howard counties this summer.

This gap can be explained by taking into account upside potential from the prolific Spraberry formation in Martin County, bordering the sub-economic Northern Extension sub-play. Unlike other deals, the W&T package is not exposed to the Spraberry.

28 August 2015
Water management: the next wave of upstream cost savings?

Water-handling charges, which have remained stubbornly high throughout the shale boom, are coming under greater scrutiny as operators look for innovative ways to recycle costly flow-back water.

Although Marcellus operators have trimmed 14% from total well costs in the past year, water costs continue to grow, totalling $1.4 million per well on average.

SW Marcellus well cost example

As a result, Antero Resources recently invested $275 million to develop a 60,000 b/d wastewater treatment facility in West Virginia and has predicted cost savings of $150,000 per well.

Similarly in the Permian, Pioneer has just signed a $117 million contract with the city of Odessa, guaranteeing access to up to five million gallons per day of treated municipal wastewater for 11 years.

The water will feed the company's 20-mile water pipeline system under construction in Midland county. Pioneer is to pay $6.33 per thousand gallons and expects to reap savings of $500,000 per well when the entire system is operational.

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21 August 2015
Shrinking crude prices spark further high-grading
As a result of unscheduled downstream bottlenecks, last week WTI drifted below $42/bbl - a level last reached in 2009 - and WCS reached $25, its lowest point since 2008. We expect depressed prices to persist through the end of the year and see WTI prices averaging just over $51/bbl in 2015. Clients can read more details in Global macro oils short-term outlook early August 2015.

This new low is accompanied by further high-grading of acreage and rig fleets, as well as greater cost cuts. We estimate that many onshore assets need to make a 15% further cost reduction to break even at current prices.

Exploration and production company Energy XXI has just slashed its 2016 development budget by 80% but plans to hold production flat. At this year's EnerCom Conference in Denver, operator morale was surprisingly high, with numerous companies messaging flat production volumes despite massive capex cuts. We currently model over 75% of companies with 2015 production at or above 2014 levels.

Changes in type curve

Tight oil operators

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14 August 2015
Canadian heavy crude benchmark price hits seven-year low
WCS, the heavy Canadian crude benchmark, reached US$24.60 per barrel on 11 August – the lowest levels since 2008. As crude supply rose, the WTI-WCS differential widened from about $7-8/bbl in June to $17/bbl.

WCS prices and differentials

The situation has been exacerbated by Enbridge’s shutdown of key pipelines following leaks while BP’s Whiting refinery reported an unplanned, month-long outage of its 240,000 b/d crude processing unit which could pressure the WTI-WCS differential wider for longer.

Year-to-date WTI-WCS has averaged $10.90/bbl and we expect it to average $12/bbl in 2015. Wider WTI-WCS differentials support economics for railing crude from Alberta to the US. Clients can get more details in Oil prices: Heavy discounts to Canada's heavy crude benchmark.

In a rare move last week, PBF Energy shipped crude from Western Canada to its refineries on the US East Coast via the Panama Canal. However, we do not expect this route to become the norm due to bottlenecks caused by the limited pipeline capacity from the Alberta oil sands to Canada's west coast. There is currently only one pipeline on this route which has been on allocation for over four years. PBF currently moves heavy Canadian crude by rail to its Delaware City refinery. 

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Our North America upstream research offers a unique granular perspective. From historic well-level data to detailed sub-play reports, we provide well performance, costs, economics and benchmarking analysis that will help to put you at the forefront of operations in the region.

To discover more, register your interest and we will contact you.

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