Water management: the next wave of upstream cost savings?

 

Highlighting the current 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.

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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10 August 2015

We share our insight from the latest Bakken Conference & Expo
At the recent Bakken Conference & Expo, we presented alongside government officials, leading operators, and service companies, where participants spoke extensively on what oil price would be required to encourage an uptick in activity.

Several expressed the opinion that $65 and $70 WTI was needed for completing and drilling, respectively. Taking that into consideration, city officials in North Dakota's western counties are making long-term infrastructure decisions based on oil production jobs rather than temporary jobs required for drilling and completion.

Continental Resources provided one of the most insightful presentations, noting that 7% to 11% of recoverable reserves were stranded near the toe and the heel of Bakken completions and that modifications to well setbacks would be needed to capture the bypassed resource.

A leading proppant provider also stressed that all ceramics should not be treated equally and that many high-strength ceramic proppants support more favourable production economics, despite increased costs relative to sand.

As we highlight in our Bakken Key Play report, June 2015 crude transportation and gas processing infrastructure have significantly lagged in the Williston Basin but have started to be addressed in recent years. 

Managers of crude-by-rail loading facilities who attended the conference, shared the sentiment that there is not enough oil being produced to support all of the existing projects which will likely lead to consolidation in this space. The flaring challenge continues to inspire firms to compress or liquefy the gas for rig fuel or to use the hydrocarbon for power generation. 

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31 July 2015
Operators rethink strategies in Gulf of Mexico
Persistently low oil and gas prices have exacerbated challenging economics in the Gulf of Mexico Shelf. Shelf rigs - largely jackups, inland barges, or platforms - totalled over 100 in 2008, yet there are now fewer than 11 rigs conducting drilling or workovers, while others remain idle.

Operators maintaining positions in the Shelf must concentrate capital on optimizing existing asset bases and those with oil-weighted portfolios are likely to fare better. We may also witness increased non-core and midstream infrastructure asset sales to those companies with long-term cash horizons which may help sustain operations through the downturn.

A comparable situation is unfolding in deepwater GoM as rig day rates continue to search for a bottom. Anadarko extended the contract on the two year-old ENSCO 8506 for approximately two months at a 60% discount from the previous day rate of $540,000. The drastic shift from cheaper intervention vessels to new generation rigs indicates that the softening rig market could also have a spill-over effect on the intervention vessel market.

Anadarko's investment in well plugging and abandonment (P&A) in the current environment suggests that the company has adopted a counter-cyclical approach, taking advantage of a softening rig market to fulfil its regulatory obligations.

This is a welcome decision for rig companies which have been advocating for more P&A work as a way to stabilize the market. However, we do not anticipate many other operators will take this approach and instead expect continued focus on cashflow positive projects. 

 

24 July 2015
US refinery crude runs continue to rise
In the past week, US refineries have processed record amounts of crude oil, reaching 16.9 million b/d, which is in line with our earlier forecast that refinery runs would approach 17 million b/d during summer, bolstered by higher levels of crude oil imports.

This will support the de-stocking of oil tanks, although we do expect another round of crude build in the latter part of the year.

US oil stocks were up for the week of July 17 as imports increased, buoyed by Light Louisiana Sweet gaining a premium to Brent which opens the door to light and medium crudes from the Atlantic Basin.

To date, July oil stocks are down 1.5 million barrels but, despite recent declines, US oil stocks are still 80 million barrels higher than at the beginning of 2015. 

Capacity continues to grow as KinderMorgan opened the second of its two Gulf Coast condensate splitters in July. Both projects are underpinned by takeaway agreements with BP.

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For more on our analysis of crude stock levels, see our Insight US Oil Stocks: Summer dip? [Subscription required]

17 July 2015

Bakken defies rig count drop to post monthly gains
Newly released production data for May shows that daily oil volumes from North Dakota rose by 32,000 b/d and gas increased by 98 mmcfd to an all-time high of 1.63 bcfd. The number of well completions also climbed from 102 to a preliminary count of 114 –  all coinciding with our latest projections.

While other firms have suggested that Bakken production will roll over in 2015 as a result of the recent drop in rig count, we continue to stress that acreage high-grading and more efficient drilling and completion services will enable modest production growth over the next few years.

Guidance from the play’s key operators indicates completions activity will be weighted to the latter part of the year and, as in the case of WPX, some operators will actually increase the number of rigs targeting the Bakken before the end of 2015.

Bakken Production

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9 July 2015
Permian could see increased crude-by-rail flows while California beckons
As midstream infrastructure continues to expand in the Permian to accommodate production growth, condensate output is accounting for a larger share of offtake demand. This makes crude-by-rail projects increasingly attractive to operators as condensate's high API gravity often fails to meet pipeline specifications. The proposed 500 kbd Midland-Sealy pipeline, for instance, is scheduled to begin operation in 2017 and will have the capability to batch some condensate, enabling Permian production to reach the Gulf Coast where it could be processed in splitters or exported. California – a state previously shielded from most US tight oil production – could stand to benefit from increased crude-by-rail capacity as well, providing a path to move limited quantities of Permian production into the state. At present, a 140 kbd rail unloading facility is expected to begin operation in Bakersfield in 2016.

Crude by rail

Also this week we discuss the implications of: FourPoint Energy adds to its Mid-Continent position at a price that implies some selling urgency;M&A activity could spike as expiring hedges threaten balance sheet security;Oil rig count rises for the first time in seven months with a week-on-week increase of 12;BP settles Deepwater Horizon claims for $18.7 billion, bringing finality to the company's legal challenges;Technip's restructuring announcement adds to the growing list of long-lead oil project deferrals;Rig spacing requirement in the Arctic likely to impact Shell's 2015 programme, compounding existing local challenges;Falling costs drive Shell and Nexen’s Appomattox sanction;Rogersville Shale exploration play looks to be heating up;USGS survey corroborates our findings that horizontal completions drive water volume increases, with Wolfcamp wells utilizing the most water.

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2 July 2015
Early movers have best chance to create value through M&A
Despite months of declining commodity prices, investors are now poised to capture opportunities in the energy space as speculation continues to drive equity markets.

This week, shares of Goodrich Petroleum jumped 17% after the company announced plans to move forward with two completions in the Tuscaloosa Marine Shale. Penn Virginia also recorded wild intra-day swings after an unsubstantiated report claimed the company rejected an unsolicited takeover attempt by BP.

With oil prices hovering at $60/bbl and the rig count starting to plateau, general consensus among investors signals that we are near an inflection point of a sustained price recovery. From a valuation perspective, Wood Mackenzie believes the window of opportunity to complete deals at 'fair market' valuations will be short-lived, as equity markets will begin pricing in improved outlooks 12 months from now. Assuming that the consensus scenario plays out, early movers have the best chance of creating value through acquisition. See M&A at $60 – the buying window opens.

The Permian's Delaware Basin is a growing target for M&A activity, with the southern plays generating interest from both potential new entrants and Permian veterans. While acreage valuations in the Midland Basin skyrocketed in 2014 with the rise of the Wolfcamp, Delaware Basin valuations are still reasonable enough for buyers to create value.

Also this week we discuss the implications of: US rig count rises for the first time in 30 weeks; Dry gas plays see upside as NGL prices diminish; WPX Energy expands Bakken operations with the addition of two rigs motivated by EUR boost; US infrastructure network continues to expand as Cushing gives way to "Permian triangle"; Sabine Pass cleared to expand export capacity into challenging global LNG market; Joint venture could reduce operator well costs in Powder River Basin; Magnum Hunter Resources to sell equity stake in Eureka Hunter Holdings in order to reduce debt and resume development; Common completion technique in Canada makes its way to the Bakken.

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25 June 2015
NGL market weakness to shift spend from wet to dry gas?
Recent declines in NGL prices are exacerbating the financial stress facing operators following the fall in oil prices over the past year. This is due to an oversupplied global market, driven by North American rich gas production and a lack of market access for ethane and LPG (with the exception of the Gulf Coast). While operators able to segregate their natural gasoline production are still able to recognise some value uplift from sales into the Canadian diluent market, conditions are putting pressure on the remainder of the NGL barrel.

Expansion of export capacity in the Northeast should reduce congestion in the US rail system and free up storage capacity by next year. However, the strength of global NGLs prices in the face of a surplus of light hydrocarbons remains uncertain. The only market left for these NGL streams is ethylene cracking - for which ethane is the preferred feedstock - yet prices for propane and butane are falling to position them as an economic substitute.

Shale plays with rich gas production like the Utica, Southwest Marcellus and Anadarko Woodford will be the primary sources of NGL production growth. Due to the additional costs associated with extracting, processing and transporting NGLs, some dry gas plays like the Haynesville Shale could offer better investment opportunities than wet gas plays throughout the remainder of the year.

Operator NGL exposure

Also this week we discuss the implications of: With limited development drilling upside, Itochu chooses tax loss over oil price optionality; Recent deepwater rig contract drives a 10% decline in project breakeven; Energy Transfer launches bold midstream mega-merger attempt; California crude-by-rail still on hold; if approved, Brent-WTI should narrow; The Permian looks poised to see a rebound in drilling activity; WPX shifts its weight to the Gallup adding 71 new drilling locations; Oilfield service providers respond to weaker demand by shedding assets; Alaska operators continue westward trend despite regulatory delays.

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18 June 2015
The Eagle Ford's Webb County overtakes the Barnett's Tarrant as Texas' top gas-producing county
On the surface, single-county production has little importance, but this event highlights the significant trend of the Eagle Ford as a growing gas producer.

At the start of 2014, the Eagle Ford was producing less gas than either the Barnett or the Haynesville. However, as of June 2015, Wood Mackenzie estimates that the Eagle Ford is producing approximately 5.2 bcfd of gas, which is 34% more than the Barnett and 15% more than the Haynesville.

Only 16 horizontal rigs are currently running in Webb County, but total production for the month of March averaged 1.8 bcfd according to data released by the Texas Railroad Commission.

Over the last two years, companies like Anadarko, Chesapeake, Swift, SM, and Rosetta have successfully reduced cycle times and maximized scale in the southwest portion of the play, enabling them to grow production while reducing rig count.

Dry gas production by play

Also this week we discuss the implications ofNorth Dakota rig count drops to 75, the lowest level since 2009, as the state reports a sequential decline for April; Gulfport announces a deal to acquire more than 35,000 Utica acres from American Energy Partners; Contango's first well at its N. Cheyenne Project produces a 24-hour test rate of 907 boe/d (98% oil); Chevron, Hess and Nexen strike pay at Sicily; Companies indicate an impending recovery in drilling and completion activity; Pioneer Natural Resources announces its intention to sell 640,000 net acres in eastern Colorado; Repsol concludes its winter drilling programme in Alaska with promising results.

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11 June 2015
Total US rig count fell by seven rigs, but looks to be nearing a bottom
We forecast a trough in the oil rig count in the third quarter and expect increasing activity levels in the fourth quarter of 2015. Higher drilling levels late in the year will provide the catalyst for oil production growth in 2016. In the absence of a hotter-than-normal summer, the natural gas rig count is likely to come under further pressure from sub-US$3.00/mmbtu prices this summer.

Weekly changes in US rig count

Also this week we discuss the implications of: US production to remain resilient; US is once again the world's largest importer of oil; Energy Transfer Partners Revolution project to expand the company's Appalachian midstream presence; Enbridge receives approval for Sandpiper Pipeline stretch in Minnesota; Permian infrastructure continues to expand as production growth rolls on; PennTex Midstream Partners IPO represents the most recent MLP to form since oil prices fell in late 2014; Woodside signs Port Arthur LNG Memorandum of Understanding; Corroboration of estimated service cost reductions; Enhanced completions being used on half of all Bakken wells; US Environmental Protection Agency (EPA) draft assessment report on the impact of hydraulic fracturing on drinking water.

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3 June 2015
Pioneer to direct proceeds from EFS Midstream sale to accelerate drilling in the Wolfcamp
Of the $2.15 billion Enterprise will pay, Pioneer owns 50.1% and will receive net proceeds of $900 million after-tax (half in Q3 and half a year later). It will also benefit according to company estimates by approximately $200 million in fee reductions for downstream processing and transportation from Enterprise.

Pioneer plans to add two horizontal rigs per month in the northern Wolfcamp and Spraberry through the end of the year, increasing the 2015 capital budget by $350 million. By the end of Q1 2016, the company expects to be back up to 36 rigs from 16 currently, which would match its rig count prior to the downturn in oil prices.

Previously, Pioneer's production was set to roll over in Q3. Despite the rig additions the company will only complete 10 more wells in 2015 than initially expected. This signals that the company is content with where it has guided 2015 production, and it will enter 2016 poised for growth. 

Also this week we discuss the implications of: LLOG successfully appraises Taggert and makes a discovery at Anchor & Crown in GoM; The current level of WTI contango does not cover the cost of storage; Rig count continues to drop but EIA production data increases; Oklahoma becomes the latest state to block local control over hydraulic fracturing regulation; Equipment failure delays Chevron's Big Foot Deepwater GoM project; The US Department of Energy conditionally authorizes ExxonMobil's Alaska LNG (AK LNG) Project to export to non-FTA countries; Tall Oak Midstream supplies takeaway capacity to STACK; Apache restructures its operating regions and consolidates its offices

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28 May 2015
Vanguard Natural Resources to acquire Eagle Rock Energy Partners for $614 million 
The acquisition will provide the MLP with stable cash flows for distributions while also providing upside from unconventional targets in the Mid-Continent.

This is the second deal in the past two months for Vanguard; the company acquired LRR Energy on April 21 for $539 million. The majority of Eagle Rock's production, similar to LRR, comes from mature, low-decline assets near Vanguard's existing production that fit well with the upstream MLP business model.

Despite the low-risk nature of the acquired assets, the acreage offers exploration upside from unconventional plays in the Anadarko Basin including the SCOOP where the best areas of the play break even below $50/bbl.

However, creating value by drilling exploratory formations is a risky and capital-intensive process, which does not necessarily support the MLP model that is based on predictable and stable cash flows.

Also this week we discuss the implications of: Hercules Offshore sells four jackup rigs and cold stacks 11 other rigs; Emerald Oil no longer plans to carry through its offering of common stock, due to market conditions and potential dilution; Sabine Oil & Gas enters into a forbearance agreement with its second lien lenders; American Energy seeks to restructure existing debt through a creative exchange offer and a separate debt offering; The Association of American Railroads reports a 14% drop in crude-by-rail activity in Q1 2015; Total US rig count falls by three to 885.

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20 May 2015
Bakken activity stages a comeback 
On 13 May 2015, the North Dakota Industrial Commission released preliminary March data which indicated a monthly increase in completions and production. Completions rose sharply from 42 in February to 189 in March while crude oil production increased from 1.18 to 1.19 mmb/d.

A drop in production and completions earlier in the year led some in the industry to speculate that Bakken production was beginning to plateau. But recent data suggests that the brief lull was more likely related to harsh weather conditions–and perhaps completions delays due to tax relief put in effect on 1 February–rather than the low oil prices.

Despite the less than ideal circumstances, the number of monthly well completions averaged 111 during Q4 2014 and Q1 2015–10% higher than the number required to keep production flat.

In our view, the combination of a potential lower extraction tax and expectations of higher oil prices during H2 2015 should at least keep activity at current levels and lead to modest growth over the course of 2015.

Although rig counts in the Williston Basin are at a five-year low, they have held steady through May. Only the best parts of the play are being drilled, evidenced by where rigs are now concentrated. Moreover, even in a reduced drilling scenario, the backlog of close to 1,000 uncompleted wells has the potential to provide a quick boost to Bakken production volumes. 

Other topics discussed in this week's update: Companies utilize a variety of financing options to repay current obligations; Cheniere Energy takes FID on Corpus Christi LNG; The Governor of Texas signs House Bill 40 which would pre-empt municipalities from banning hydraulic fracturing within city limits, effective immediately; The Oklahoma Corporation Commission's (OCC) issues new wastewater disposal directives; UGI, a utility in the Philadelphia area, has proposed a small-scale liquefaction plant in the heart of the Marcellus Shale; XTO Energy (ExxonMobil) plans to expand its natural gas processing capacity in Butler County; The US drops six rigs, the lowest decline in 23 weeks; Wood Mackenzie predicts oil fundamentals are improving.

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13 May 2015
American Eagle Energy becomes the fourth US E&P to file for bankruptcy following the oil price collapse 
Along with Quicksilver Resources, BPZ Resources, and WBH Energy, American Eagle filed for Chapter 11 bankruptcy protection on 8 May 2015. The company lists $215 million in debt and $212 million in assets primarily located in Divide County, ND in what we define as the North Williston sub-play of the Bakken/Three Forks.

In December of last year, the company suspended all drilling on its properties and missed its first interest payment in March 2015.

We estimate that American Eagle Energy's sub-play breakeven is $64/bbl (WTI), roughly 10% lower than the sub-play average. According to the North Dakota Industrial Commission, of the 85 rigs currently active in the state, only three are drilling in this particular sub-play. It would require just over $70/bbl for most operators in this sub-play to earn a 10% return on investment.

Should the recent oil price rally stall at current levels, drilling here will remain uneconomic even factoring in the shape of the futures curve. We could see other operators consider bankruptcy as the most expedient option to get out from under an unmanageable debt load.

Other topics discussed in this week's update: Baker Hughes reports that US rig activity declined by the lowest level over the past 22 months; Magnum Hunter appears to be close to finalizing its anticipated Utica farmout; The Permian remains ripe for consolidation as 82,000 acres were exchanged through four separate transactions last week; BOEM removes the most significant hurdle to Shell's Chukchi Sea exploration programme; With Bakken production growth slowing and arbs still open to the east and west coasts, the need for a large Bakken-WTI discount to provide for transport by rail to the Gulf Coast has waned; Texas RRC shuts in disposal wells after earthquake; Wood Mackenzie poll reveals an industry perception that a price of $3.00-3.50/mcf is required for gas plays to compete with tight oil; Williams agrees to acquire all public equity of Williams Partners L.P. for a total consideration of US$13.8 billion in an all stock-for-unit deal.

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6 May 2015
BP indicates that rig rate cost deflation should help Mad Dog Phase II move forward 
The project (BP 60.5%, BHP 23.9%, Chevron 15.6%) has been through multiple revisions as partners tried to come up with an optimal development solution. Originally it was to move forward as a spar with a platform rig, then as a semi-submersible without a platform rig. At one point, it was rumoured to be developed as a smaller tie-back to existing infrastructure.

In December 2012, BP outlined plans to move forward with the project; however, it put these plans on hold in April 2013. The project was expected to re-enter FEED by mid-2014 but was further delayed. BP now expects the project to move through an FID this year.

Securing favourable rig rates will be one of the project prerequisites, as this is expected to be the main source of cost savings. In some cases, rig rates have already fallen more than 30% from their peaks. Rig rates accounted for approximately 50% of D&C costs at peak rig pricing, and such a steep drop in day rates could help improve project economics.

In addition, BP is contemplating using an EOR technique which could help improve recovery by 5-10%, further improving economics. Wood Mackenzie estimates that Mad Dog (all three phases) holds almost 1,000 mmboe in reserves and Mad Dog Phase II accounts for 37% of those reserves. The project has an estimated remaining NPV10 of $10.9 billion.

Other topics discussed in this week's updateHess cuts costs, reinforces Bakken inventory position; Northeast Marcellus gas production to slide in the second quarter; Whiting continues trend of industry squeezing more from less; Key Energy earnings highlights relative resiliency of production-related services; Statoil to test the use of CO2 in the Bakken; QEP pursues improved well performance in the Rocky Mountains with new completion designs; Anadarko announces a $2.78 billion post-tax impairment charge on its Greater Natural Buttes field; New rules won't derail crude-by-rail; WPX sells Marcellus firm transport agreements for US$200 million in cash; ONEOK rebuffed in attempt to obtain right-of-way on Fort Berthold.

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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.

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