NGL market weakness to shift spend from wet to dry gas?

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

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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