Producer Breakevens

© Copyright 2015 RBN Energy

© Copyright 2015 RBN Energy, LLC - 1 -

A RBN Energy Drill Down Report

oduction

In recent days the relentless fall in crude prices seems to have slowed, but a further decline is certainly possible, if not likely. As everyone who watches the oil market knows by now – the price crash has resulted from an oversupply of crude in world markets, partially due to relentless increases in production from U.S. shale plays which have pushed out almost 5 MMb/d of net crude oil and petroleum product imports over the past five years. At this point there appears to be little sign of enough short term demand increases to soak up excess barrels or cutbacks by major producers – including OPEC. Here is where we are today – in a market still searching for a bottom. The price of CME NYMEX crude futures for U.S. domestic benchmark West Texas Intermediate (WTI) is down 57% from its high of $107/Bbl in June 2014 to $45.59/Bbl – including a fall of 14% so far in 2015. The price of international benchmark crude Brent ICE futures has tumbled equally far and fast – down 58% since June 2014 and 15% so far in 2015 to $48.79/Bbl on January 23, 2015. Brent premiums to WTI have averaged less than $3/Bbl this year so far compared to an average of $6.50/Bbl during 2014, removing some of the price advantage that domestic crudes have held over international competitors for much of the past four years. On its

The more than 50% fall in crude prices since June 2014 and 30% fall in natural gas since November 2014 have crushed producer internal rates of return (IRRs) for typical wells in U.S. shale plays.

Analysis of IRRs and crude breakevens provides insight into what will happen to production as producers scramble to respond.

Continued growth in shale production is related to IRR economics, but with several caveats that affect producers including high IRRs in drilling sweet spots, the impact of hedging, HBP, lower services costs and the number of hold over completions from last year.

This report includes results from IRR and breakeven sensitivity analysis by basin and commodity using the RBN Production Economics model and input well data from a variety of sources.

Coming up with input variables that represent wells in different plays is as much art as science. To fully understand the significance of the analysis, it is important that you know what you are looking at. We lay out our analysis for you so you can make your own judgments about our methodology and model input data.

It Don’t Come Easy: Low Crude Prices, Producer Breakevens and Drilling Economics


It Don’t Come Easy

own, this crude price carnage is enough to throw a curve ball at producer rates of return for U.S. shale oil plays. To cite just one example, RBN’s analysis indicates that producer internal rates of return (IRR’s – calculated as the discounted cash flow rate of return) for a typical oil well in the North Dakota Bakken shale play fell from 39% in the fall of 2014 with WTI priced at $90/Bbl to just 1% in January 2015 with WTI at $45/Bbl. This is the first time since the onset of the shale revolution in crude oil markets that prices, and thus rates of return have seen such declines. These markets are now in uncharted territory.

As if the oil market free fall were not enough, a mild start to the 2014-15 winter and continued high production of natural gas have combined to push prices for U.S. benchmark Henry Hub, Louisiana CME NYMEX natural gas futures below $3/MMbtu for the first time since 2012. These low prices are crushing the returns that producers make from dry natural gas shale plays – reducing typical IRRs in the Louisiana Haynesville dry gas shale play from 5% at $3.75/MMBtu gas to -4% at $3.00/MMBtu. (Note that for emphasis we show negative returns in red.) And despite falling natural gas prices, the ratio between WTI crude and Henry Hub natural gas is languishing at 16X (meaning crude in $/Bbl is 16 times the price of natural gas in $/MMBtu). That compares with a high ratio of 54X in 2012 and an average of 27X between 2009 and June 2014. This narrowing in the ratio between crude and natural gas prices has a knock-on effect on shale producer returns from “wet gas” plays. Prices for NGL’s (the “liquids” extracted from wet or rich gas at gas processing plants) are also at multi-year lows – squeezed down by tumbling crude prices. That means typical IRR’s from drilling in wet gas plays no longer get an uplift from higher NGL prices. As an example, previously healthy IRR’s of 24% for typical wells in the South Texas Eagle Ford play at $90/Bbl crude and $3.75/MMBtu natural gas have fallen to -3% in 2015 at $45/Bbl crude and $3/MMbtu gas.

A somewhat counterintuitive point in all of this is that the immediate, short-term impact on the production volumes of crude, natural gas and NGL’s resulting from the price crash is likely to be minimal. Existing wells that are currently flowing will continue to produce – there is no value to shutting in output because of falling prices. Even at today’s prices, the per-unit revenues of existing wells are significantly above operating costs. In fact, production is likely to increase in the near term for at least four reasons: (a) Producers are cutting back drilling, but the rigs that are left are focused on their highest yield “sweet spots”, the best, largest producing opportunities. The producer’s goal is to maximize revenue, and that means maximize production volume. (b) In recent years a number of leases signed by producers have HBP (held by production) clauses, requiring drilling and production to hold leases that were acquired at significant costs. Some wells will be drilled and produced to hold these leases, regardless of short-term economics. (c) Some producers were wise enough to hedge their prices, and will continue to drill and produce against those higher priced forward sales, and (d) producer economics will be improved by lower drilling service costs, which are coming down fast in response to lower drilling activity.

However, there is no doubt that over time lower prices will result in producers cutting their budgets for drilling new wells. This is already happening in shale plays across the country as producers, small and large, review how much they will invest in new production during 2015 and beyond. The analysis in this report lies at the heart of those investment decisions – determining which plays offer the best rates of return in a lower price environment.

Independent producers do not typically have the same deep pockets or access to bank finance as major oil companies. Continued drilling programs require new financing that either has to be borrowed or generated as cash flow from existing wells. The oil price crash has basically halved the revenue from existing wells. We calculate that U.S. shale producers can expect to receive about $66 billion less cash flow revenue from existing crude production with prices at year end 2014 levels ($53/Bbl) than at $100/Bbl. That revenue is not now available for new drilling budgets



or to pay off existing bank loans. As a result producers need to be far more selective about where and when to drill.

Those decisions – how much to drill – when to drill and where – will determine the impact on crude, natural gas and NGL production during 2015 and beyond. As the number of rigs deployed to drill new wells declines, so will the rate of increase in production. As existing well flows decline, overall production will eventually fall unless enough new wells are drilled to replace the resulting drop in output or new wells are proportionately more productive. Whether enough new wells are drilled to maintain an increase in overall crude production will depend on drilling economics and the related appetite for new investment by producers. The latest Energy Information Administration (EIA) forecast (January 2015) indicates that U.S. crude output will increase in 2015 by 600 Mb/d to 9.3MMb/d and by 200 Mb/d to 9.5MM b/d in 2016.

For the moment producers are reviewing drilling programs and making selective cutbacks. Detailed information provided on rig deployment in North Dakota by the State Industrial Commission indicates the drilling rig count in that State was down from 191 in October 2014 to 181 in December 2014 and 156 in mid-January 2015 – a reduction of 35 rigs or 18% since October. Weekly national drilling rig counts from Baker Hughes show the total rig count (for oil and gas directed rigs) falling by 15% since mid-November 2014 with oil directed rigs down 17% since then. While drilling rig counts are an obvious and important leading indicator of production it should be noted that dramatic increases in rig productivity (output per rig) have been achieved in the past four years. As a result new well production numbers are frequently higher than existing wells – slowing the production decline even as the rig count falls and as we have said – allowing for overall continued increases in production. In most cases we expect producers looking at drilling program budgets today to concentrate their investment in the “sweet spots” of existing plays – where production and IRRs will be optimal. In such a lower price environment there are few budget dollars available for experimental drilling at the fringes of established plays to discover new opportunities. As stated above, expect instead to see reduced drilling, concentrated in sweet spots.

The primary purpose of this RBN Drill Down report is to provide an explanation and summary of analysis produced using RBN Energy’s Production Economics Model to indicate what we believe are typical IRRs in different crude oil and natural gas price scenarios for major shale plays across the U.S. The analysis segments wells as to whether they produce predominately oil, dry natural gas or wet natural gas (containing NGLs) but incorporates the production of all three hydrocarbons in basins were most wells are “triple plays”. We also provide data for sweet spots in oil plays – to demonstrate that new drilling will continue in some locations with high IRRs even if prices continue to fall. In addition to IRR’s we provide an analysis of breakeven prices for crude oil plays – calculated as the price that results in a zero % IRR in a given natural gas price scenario.

We also provide a thorough description of the assumptions behind our analysis using the RBN Production Economics model. We introduced the model in the fall of 2013 as part of our blog series “The Truth is Out There - Unconventional Production Economics”. That first iteration looked solely at one commodity – natural gas. Last year (2014) we expanded the model to cover all three “drill-bit hydrocarbons” – crude oil, natural gas and NGLs. We used the expanded version as part of our Drill Down report on growing production in the Permian Basin last May (see Stacked Deck) and we provided a downloadable version of the spreadsheet model with that report. This time we provide summary analysis based on running multiple sets of data and scenarios through the model.



The report layout is as follows:

In Section 1 we provide background and detail on the price crash, crude-to-gas ratio and the impact on producer revenues.

In Section 2 we review the basics of shale drilling technology and productivity enhancements that continue to improve drilling efficiency.

In Section 3 we discuss the assumptions and input variables used in RBN’s IRR and breakeven analysis using the Production Economics model.

In Section 4 we present the results of our IRR and breakeven analysis

The U.S. oil and gas industry has entered a new phase in 2015, characterized by revolutionary new technologies that reduce the per-unit cost of production, and now lower prices, that make those lower costs essential to viable production economics. The only way to grasp how this drama will play out over the next few years is to have a full appreciation of how those economics will impact the behavior of U.S. producers. The goal of this RBN Drill Down report is to shed light on some of the most important calculations that will impact that behavior.

This report is provided for the exclusive use of the Subscribing Customer. It is not permissible to make copies of this report for distribution to anyone who is not a Subscribing Customer.

The data and information in this report may be wrong. This report has been prepared using publically available data and information sourced primarily from internet websites including company presentations, press releases and media reports. The topics covered are subject to continuous revision. Some of these revisions may not be reported publically. Some of the reported information used in this report may be erroneous. Accordingly, this report is subject to errors and inaccuracies. You should not rely on any information provided in this report as the basis for any decision or conclusion regarding the topics covered by this report.

The information and data in this report are provided on an “as is” basis. RBN Energy, LLC makes no warranties as to the accuracy or completeness of any information or data in the report. RBN Energy, LLC, shall be not be liable for any loss or damage arising from any party’s reliance on the contents of this report and the companies disclaim any and all liability related to the use of this report to the full extent permissible by law, whether based on warranty, contract, tort or any other legal theory.



Table of Contents

Introduction ..................................................................................................................... - 1 -

Section 1 – Prices and Production ...................................................................................... - 7 -

1.1 Price Crash ........................................................................................................... - 7 -

1.2 Cash Flow Impact of the Price Crash .................................................................... - 8 -

1.3 Production Impact ................................................................................................. - 9 -

Section 2 – Drilling Technology ........................................................................................ - 11 -

2.1 Background ......................................................................................................... - 11 -

2.2 Horizontal Drilling and Fracking 101 ................................................................... - 12 -

2.3 Evolution of Fracking ........................................................................................... - 13 -

2.4 Productivity Improvements .................................................................................. - 14 -

Section 3 – Scenario Analysis Assumptions and Variables ........................................... - 14 -

3.1 Drilling and Completion Costs ............................................................................. - 15 -

3.2 Operating Expenses ............................................................................................ - 16 -

3.2.1 Production Taxes .................................................................................... - 16 -

3.2.2 Royalty Rates .......................................................................................... - 16 -

3.3 Initial Production, Decline Rates and Estimated Ultimate Recovery ................... - 16 -

3.4 RBN Production Economics Model Analysis ....................................................... - 18 -

3.4.1 Decline Rates and Decline Curves .......................................................... - 18 -

3.4.2 Estimated Ultimate Recovery .................................................................. - 18 -

3.4.3 Cost Inputs .............................................................................................. - 18 -

3.4.4 Production Inputs .................................................................................... - 19 -

3.4.5 Commodity Price Inputs .......................................................................... - 19 -

3.4.6 Model Outputs ......................................................................................... - 20 -

3.5 RBN IRR and Breakeven Analysis ...................................................................... - 21 -

3.5.1 Coverage and Categorization .................................................................. - 21 -

3.5.2 Premises ................................................................................................. - 22 -

Section 4 – IRR and Breakeven Analysis Results ........................................................... - 23 -

4.1 Then and Now ..................................................................................................... - 23 -

4.2 Typical Oil Plays .................................................................................................. - 25 -

4.3 Sweet Spots in Oil Plays ..................................................................................... - 26 -

4.4 Breakeven Analysis of Crude Plays .................................................................... - 27 -

4.5 Gas Liquids Plays – Alternative Crude Price Scenarios...................................... - 28 -

4.6 Gas Liquids Plays – Gas Price Scenarios ........................................................... - 29 -



4.6.1 Crude and Liquids Sensitivity to Oil Prices .............................................. - 30 -

4.6.2 Dry Gas Plays – Gas Price Sensitivities .................................................. - 30 -

4.6.3 Gas and Liquids Sensitivity to Gas Prices ............................................... - 31 -

Conclusions ................................................................................................................... - 32 -



Section 1 – Prices and Production

1.1 Price Crash

Drill bit hydrocarbon prices (crude, natural gas and NGLs) have been in free fall. The price of CME NYMEX crude futures for U.S. domestic benchmark West Texas Intermediate (WTI) is down 57% from its high of $107/Bbl in June 2014 to $45.59/Bbl (January 23, 2015) – including a fall of 14% so far in 2015. The price of international benchmark crude Brent ICE futures has tumbled equally far and fast – down 58% since June 2014 and 15% so far in 2015 to $48.79 on January 23, 2015. Brent premiums to WTI have averaged less than $3/Bbl this year so far compared to an average of $6.50/Bbl during 2014, removing some of the price advantage that domestic crudes have held over international competitors for much of the past four years. In addition a mild 2014/2015 winter so far and continued record dry gas production in the Lower 48 has resulted in lower prices for natural gas since November 2014. Prices for CME NYMEX Henry Hub natural gas futures delivered to the Henry Hub in Louisiana are down 30 % to $2.986/MMBtu (January 23, 2015) since November 2014 and have averaged less than $3/MMBtu in recent weeks. The chart in Figure 1 below shows Brent (red line) and WTI (blue line) in $/Bbl against the left axis and Henry Hub futures (green line) in $/MMBtu against the right axis. All three commodities have been headed in the same direction – down (black dotted oval on the chart).

Figure 1 – Crude & Natural Gas Prices; Source: CME Data from Morningstar

Despite falling natural gas prices, the ratio between WTI crude and Henry Hub natural gas is languishing at 16.3X (meaning crude in $/Bbl is 16.3 times the price of natural gas in $/MMBtu). That compares with an extremely high ratio of 54X in 2012 and an average of 27X between 2009



and June 2014. The low crude to gas ratio has important implications for NGL’s (the “liquids” extracted from wet or rich gas at the wellhead). NGLs are also at multi-year lows – squeezed between tumbling crude and low natural gas. The Frac spread is an indicator of natural gas processing margins – the spread between the energy equivalent Btu price of a basket of NGLs weighted by typical volume processing yields and the price of natural gas. The higher the Frac spread, the more profitable it becomes to extract liquids from wet gas NGL plays. The Frac spread was above $8MMbtu in February 2014, but as NGL prices fell it dropped below $4.00/MMbtu in November and in January 2015 the spread fell below $2.00/MMbtu - indicating that gas processing is uneconomic at many processing facilities. Lower Frac spread values reduce drilling returns in wet gas NGL plays.

It is this triple price whammy that U.S. shale producers are scrambling to come to terms with in developing their 2015 drilling programs.

1.2 Cash Flow Impact of the Price Crash

Funds for most producers to pay for continued drilling and increased production rely heavily on cash flow generated from existing operations. That cash flow is either used to pay for new drilling or to pay down borrowing for existing well development. With less operating cash or financing available, new drilling will be curtailed. Because of this reality it is important to understand that there has been a sea change in the fortunes of U.S. shale producers as a result of the price crash. The following high-level estimate of the cash flow impact on crude oil production returns illustrates the scale of the challenge for just one commodity.

Figure 2 – WTI Prices 2013 & 2014; Source: CME Data from Morningstar

Between January 2009 and January 2015 U.S. monthly crude production increased by 3.8 MMb/d to 9.1 MMb/d according to the Energy Information Administration (EIA) weekly estimates. Since this 3.8 MMb/d has primarily been an increase in shale production – mostly from the Bakken, Permian and Eagle Ford basins - we can use that number to estimate shale producer



revenues before the price crash and after. Figure 2 shows crude prices for U.S. benchmark West Texas Intermediate (WTI) during 2013 and 2014. Up until the high price of 2014 – on June 7th – the average WTI price over this period was $99/Bbl (green dotted line). After the crash, prices fell sharply for the rest of the year to end at $53/Bbl – about 46% below the previous $99/Bbl average (red arrow). At $99/Bbl the 3.8 MMb/d of shale crude production since 2009 would generate about $0.38 billion per day or $139 billion per year. That means shale producers could expect as much as $139 billion revenue from production during 2014. With crude prices falling 46% in the second half of 2014, the revenue from that shale production would fall to 3.8 MMb/d * $54/Bbl = $0.2 billion per day. That is $73 billion on an annual basis. So in terms of drilling budgets for 2015, U.S. shale producers can expect to receive about ($139 - $73) or $66 billion less cash flow revenue from existing crude production with prices at year end 2014 levels ($53/Bbl).

1.3 Production Impact

Prior to the shale era, lower oil and gas prices would translate quickly into a visible reduction in the number of drilling rigs operating and the curtailment of new production. But today the response is much less predictable and a reduction in drilling rigs is frequently matched by an increase in production – at least in the short term. Figure #3 shows U.S. weekly drilling rig count totals from the start of 2011 – the period when oil shale production really took off. The green shaded area is the total rig count (both oil and gas) including conventional vertical drilling where the well is drilled straight down and horizontal drilling that is typically used with hydraulic fracturing to extract hydrocarbons from shale. Note that the total rig count has remained range bound between 1700 and 2000 over the entire period but was down to 1633 on January 23, 2015 - falling 15 % since November 2014. In the shale era, the number of rigs has had little or no correlation with production volumes. For example total rig count was higher in 2011 than it is today, yet crude and gas production volumes have increased dramatically since then. This disparity is caused by dramatic improvements in rig productivity meaning fewer rigs are required to extract more hydrocarbons. Also note that the gas-only rig count (red line in Figure #2) has leveled off in the three hundred range since 2013 although gas production has continued to increase - in part because oil drilling has produced more associated gas. The number of oil rigs (blue line) has fallen by 261 since mid-November in response to falling crude prices (pink dashed circle in Figure 3) but production is still increasing from existing wells coming online.



Figure 3 – Oil & Gas Rig Counts; Source: Baker Hughes

Regardless of drilling rig numbers, the immediate impact on the production of crude, natural gas and NGL’s resulting from the price crash is likely to be minimal. Existing wells that are currently flowing will continue to produce – there is no value to shutting in output because of falling prices. Even at today’s prices, the per-unit revenues of existing wells are significantly above operating costs. In fact, production is likely to increase in the near term for at least four reasons: (a) Producers are cutting back drilling, but the rigs that are left are focused on their highest yield “sweet spots”, the best, largest producing opportunities. The producer’s goal is to maximize revenue, and that means maximize production volume. (b) In recent years a number of leases signed by producers have HBP (held by production) clauses, requiring drilling and production to hold leases that were acquired at significant costs. Some wells will be drilled and produced to hold these leases, regardless of short term economics. (c) Some producers were wise enough to hedge their prices, and will continue to drill and produce against those higher priced forward sales, and (d) producer economics will be improved by lower drilling services costs, which are coming down fast in response to lower drilling activity.

However, there is no doubt that over time lower prices will result in producers cutting their budgets for drilling new wells. This is already happening in shale plays across the country as producers, small and large review how much they will invest in new production during 2015 and beyond. For example, detailed information provided on rig deployment in North Dakota by the State Industrial Commission indicates the drilling rig count in that State was down from 191 in October 2014 to 181 in December 2014 and 156 in mid-January 2015 – a reduction of 35 rigs or 18% since October.



But even as the rig count is falling, many companies have announced that they expect 2015 production to be higher than 2014. For example spending at Oklahoma City-based Continental will fall to $2.7 billion but the company will increase production by as much as 20 percent in 2015. Midland, TX-based Concho Resources cut its 2015 capital spending plans by $1 billion but projects 16-20% year-over-year production growth. Other producers are moving rigs to locations where they expect higher production, and thus higher returns. Comstock Resources announced plans to suspend its oil-directed drilling activity in shale plays in Texas and Mississippi and move two rigs to Northeast Louisiana where it would start drilling for natural gas in the Haynesville Shale in pursuit of higher returns. Analysis of a sample of company announcements compiled by U.S. Capital Advisors on January 20, 2015 indicated that 15 out of 18 independent producers who provided data expect 2015 production to stay level or increase over 2014. What is happening is that the least productive rigs are being laid up, while the most productive rigs continue to drill and yield increasing production volume.

In summary – despite the price crash, RBN does not expect to see an immediate decline in crude oil production. We expect that producers will drill fewer wells this year but that these wells will be more productive – targeting the sweet spots in existing plays. We expect production to continue to increase in 2015 and potentially 2016 as well – albeit at a slower pace. The more immediate impact will be on producers dealing with lower cash flows from existing wells and deciding where to target their future drilling programs to get the best returns on investment.

Section 2 – Drilling Technology What follows is based in part on our May 2014 “Stacked Deck” Drill Down report on RBN’s view of the outlook for Permian production. It is provided as a refresher and introduction for those less familiar with shale drilling and economics.

2.1 Background

The conventional approach to oil and gas production that dominated the industry for decades targets individual geologic "traps" of oil and gas, which are concentrated pools of hydrocarbons sealed under a cap of impermeable rock. Over millions of years, these deposits seeped up to the trap from a “source rock” below, often a shale formation. Such conventional reservoirs are relatively straightforward to develop once discovered. Unfortunately, onshore U.S. conventional fields have long been in decline and are largely tapped out. As a result, producers looking for conventional plays increasingly resorted to inhospitable locations such as deep sea offshore and northern Alaska that are expensive and challenging in which to operate.

In contrast with conventional plays, unconventional “shale” plays seek to exploit hydrocarbons that have not migrated away from the source rock and are still embedded in relatively impermeable, sedimentary geological formations such as tight sands and shale. Hydrocarbons are extracted from these formations using an innovative combination of two technologies, namely horizontal drilling and hydraulic fracturing that have been around for a long time.

What makes shale production viable is the presence of vast, continuous shale-rock formations in several major plays around the U.S., together with (a) the ability to burrow across these long formations horizontally, and (b) huge improvements in the ability to frack the rock to release hydrocarbons to flow to the well bore and up to the surface. The result? Large initial production (IP) flow rates of hydrocarbons in the first 30 days, and significant estimated ultimate recoveries (EUR - total cumulative production) per well. From an economic perspective, these characteristics translate to more production per dollar spent drilling a well, which in turn means higher rates of return on drilling investment.



Much of the credit for the innovative techniques used in the shale revolution lies with the late George Mitchell (1919 – 2013) and members of his Mitchell Energy shale gas team. Over more than a decade of trial and error in the late 1990s and early 2000s, Mitchell and his team worked to refine horizontal drilling and hydraulic fracturing (fracking) technologies to tap the vast supply of shale hydrocarbon resources that unconventional drilling now provides.

2.2 Horizontal Drilling and Fracking 101

To drill a horizontal well, the operator first drills vertically to a depth just above the shale formation called a “kick-off point". Drilling is then continued horizontally through the shale formation to the desired lateral length. During the process of drilling, several casings are installed--think of them as metal sleeves. Casing is held in place by cement that isolates the well from the surrounding geology (see Figure 4).

Figure 4 – Shale Drilling Technologies; Source: Department of Energy



The key to the large initial production rates and EUR’s exhibited by shale wells is that horizontal orientation. Why? The entire length of the extended horizontal well bore after hitting shale comes into direct contact with the pay zone. Think of it this way: vertically drilling into a conventional reservoir allows only a few hundred feet of contact between a well and a formation, but drilling a shale well horizontally allows several thousand feet of contact between the well and the formation. Many of these horizontal wells in shale basins have horizontal “laterals,” extending 5,000 to 12,000 feet in length, or longer.

After drilling, the next stage is well “completion.” Operators progressively perforate the well in stages, working back from the end of the horizontal lateral, using explosives to “blow” small holes (perforations) through the casing. Then comes hydraulic fracturing, a technique used for decades in both vertical and horizontal wells to create fissures in the rock to release gas and liquid hydrocarbons.

Using heavy horsepower, the operator pumps a mixture of water and chemicals at very high pressure into the well and out through the perforations. The resulting pressure cracks or fractures the surrounding shale, creating permeable passages from the greater formation to the well bore. However, once the water pressure is reduced the fractures would quickly close again, so to prevent this, operators also add to the frack fluid a quantity of small crush-resistant particles, usually sand, called proppants. These proppants move into the fractures and hold them open after the pressure is reduced. The process of perforation and fracturing is conducted in stages back from the end of the horizontal lateral with short lengths of the well bore being completed one after another. Accordingly the cost of completion is somewhat proportional to the number of frack stages performed.

2.3 Evolution of Fracking

When “shale gas” grabbed the public consciousness in the late 2000s, companies initially targeted “dry gas” (gas which is mostly methane; minimal NGL content) wells in the Barnett shale near Fort Worth and Dallas, the Haynesville shale of Louisiana, the Fayetteville shale of Arkansas, and the Marcellus shale of Northeast Pennsylvania. Gas flowed out of fractured rock so well that the ensuing oversupply depressed domestic gas prices. Those lower prices discouraged more drilling, and eventually the natural decline rate of the wells overtook volumes from the fewer new wells, resulting in decreasing production in some of these plays. One major exception to this trend has been dry gas in the particularly prolific and profitable gas wells in the Marcellus and Utica plays near Northeast consumers.

Fortunately those same technologies worked equally well for ‘wet’ natural gas – plays where the gas has a high British Thermal Unit (BTU – a common measure of energy) content which, when processed, yields significant quantities of NGLs valued by (among others) petrochemical, refining and retail propane markets. As liquids, NGLs are generally priced closer to crude oil than to natural gas and so when the crude to gas price ratio is wide (as it was between 2009 and June 2014), NGLs were priced considerably higher on a BTU basis than “dry” (predominately methane) natural gas. The higher value of NGLs encouraged gas drillers to move away from dry gas basins and towards wet gas liquids plays, and that was a big factor in continued increases in natural gas production. But there are a limited number of those wet gas plays. Eventually producers turned the focus of shale technologies to crude oil. The price of oil, set on international markets, more than doubled after the Great Recession, returning to pre-crisis levels of over $100/Bbl and dramatically diverging on an energy-equivalent basis from gas prices. This divergence of crude and natural gas prices provided the impetus for shale producers to begin exploiting oil plays such as the “big three” - the Bakken, Eagle Ford and Permian Basins using horizontal drilling and hydraulic fracturing. The result was a shift in focus by producers with the



option to move their drilling budgets and activities away from dry gas and towards crude oil and liquids-rich gas plays.

2.4 Productivity Improvements

The evolution of fracking technology has been characterized by continuous improvement in drilling productivity – bringing down the costs of drilling and completing wells at the same time as increasing well IPs and EURs. Two of the more important techniques developed are:

Multiple Well Drilling Pads: many laterals can be drilled in several directions from one drilling site. The same horizontal drilling rig can be moved slightly to extend a new lateral instead of packing up and moving to a new location to drill a new well.

Stacked Plays: as fracking technology has improved, operators have learned how to “crack the code” in more complex formations with multiple layers of shale such as the Niobrara in the Rockies, the Bakken in North Dakota and Wyoming, and Permian basin in Texas and New Mexico. Wells in these stacked plays produce a combination of oil, gas and NGLs - increasing producer IRRs. By obtaining a lease with optionality, producers can drill wells over and over on the same stretch of land, targeting different geological levels in stacked “pay zones.”

All this is good for the management of costs. Producers keep their infrastructure, crews, subcontractors and materials in roughly the same area over a longer time, and do not have to relocate to reinvent the wheel as often. Even moving rigs is getting more efficient with “walking” rigs that can mechanically move a short distance to their next location.

These productivity improvements have been achieved at a time of higher oil prices when rates of return for drilling were high – permitting experimentation. In the coming period of lower oil and gas prices we expect to see productivity improvements continue under the incentive of lower revenue streams. Other “service” costs provided by drilling support companies should also be pressured downward in a period of lower demand.

Section 3 – Scenario Analysis Assumptions and Variables Methodologies for calculating the economics of oil and gas producing wells are quite complex, requiring sophisticated models, considerable technical expertise and more data than is usually available to analysts. However, it is possible to approximate the results from these sophisticated models using a simple spreadsheet model and a few critical input variables. That is the intent of the RBN Production Economics Model, which uses only seven input factors. These factors are:

Drilling and Completion Costs – what it costs to drill the well and ready it for production

Operating Expenses – the ongoing cost of operating and maintaining the well Production Taxes- taxes due to government entities based on oil and gas

production Royalty Rates – the amount owed to the owner of the ‘mineral rights’ where the

well is located Initial Production Rate – the rate of flow for the well when it first goes into

production Decline Curves – the rate of production decline over the life of the well Commodity prices – the price at which the oil, NGLs and gas are sold



The analysis in Section 4 was generated using the RBN Production Economics Model to compute returns (IRRs) for both typical and sweet spot wells in oil, gas and NGL shale plays. In this section we provide details and explanations of the model inputs.

Note that the cost of acquiring the lease and any exploration costs are not included in our list of variables. We confine our analysis to ‘half cycle economics’ - a term that means we compute the rate of return based on the incremental cost of drilling the well, offset by the revenues from products from that well. Since any exploration costs and the cost of acquiring the lease are for the most part already ‘sunk’, they are not included in our analysis.

3.1 Drilling and Completion Costs

Developing a well is a two-part process. The first is drilling: putting roads in to the well site, leveling dirt for the drilling pad and platform, prepping the site, mobilizing the rig, drilling the well, and cementing the casing. The second part is completion: hydraulic fracturing to stimulate flow from the well and putting the infrastructure in place to get the well’s production to market. The two pie charts in Figure 5 give an idea of the relative proportions of drilling and completion costs spent at each stage.

The actual cost of drilling a single unconventional horizontal well is chiefly a function of the depth of the formation and the lateral length drilled through it. A short lateral (horizontal) may have a length of 5,000 ft. Longer laterals get up to 12,000 feet and are considerably more expensive.

Figure 5 – Breakdown of Representative Horizontal Well Costs; Source: RBN



By far the largest part of completion cost is fracking (hydraulic fracturing), or well stimulation. Other costs include perforation of the well casing, handling of flowback water, tubing and surface equipment, and facilities costs.

The number of fracturing stages is a primary determinant of completion costs. In each fracturing stage the well casing is perforated and water, chemicals and proppant are injected under high pressures into the shale to cause fractures. When the water recedes the proppant (usually silica sand) holds open the fractures so that the hydrocarbons can flow into the well bore.

The drilling and completion costs for wells used in our analysis ranged from less than $1 million to $12 million.

3.2 Operating Expenses

Well drilling and completion can be considered the fixed costs of production. Once the well is producing hydrocarbons, there are a number of variable operating costs. These variable costs may be broadly grouped into two buckets - operating expenses and royalties and taxes.

Operating expenses are direct costs associated with operating each individual well together with the gathering system that connects the wells to a processing plant or pipeline interconnect. They are generally split between lease operating expenses and gathering and transportation costs.

3.2.1 Production Taxes

In most U.S. oil and gas fields, producers are required to pay a production or severance tax based on the gross production revenue generated at the wellhead. The gross production revenue - the final sale price of the oil and gas at the wellhead, less the transportation cost to get it to market. When dealing with severance tax it is important to remember that the mineral rights owner usually must pay his/her portion of the severance tax out of their royalty payment.

3.2.2 Royalty Rates

The royalty is an agreed upon percentage of the gross production revenue, before production costs, paid to the owner of the mineral rights. Usually producers do not directly own either the land or the mineral rights for drilling locations and must lease those mineral rights from the owner. The owner of the mineral rights may or may not be the surface owner. The minerals lease will typically include a bonus, paid up front (and ignored in our analysis since we are computing half cycle economics, as described previously) and a royalty rate.

3.3 Initial Production, Decline Rates and Estimated Ultimate Recovery

The relationships between three critical variables determine a well’s production over time. Those three variables are; the initial production rate (IP – the production rate during the first month), the decline rate (meaning the rate at which production declines over time) and the estimated ultimate recovery, or EUR (meaning the total well lifetime production).

Figure 6 plots the relationship between the daily crude oil production curve (blue line, left axis) and the cumulative crude oil production curve (red line, right axis) for the 25-year lifetime of a representative well in the Permian basin.



Figure 6 – Daily Oil Production Curve & Cumulative Production Curve; Source: RBN

The well has a high crude oil IP rate of 475 b/d (blue line, first month of production). The rate of production falls off a steep 55% in the first year, 30% the second year, and a declining percentage each year thereafter until the decline curve comes close to flattening out (numbers detailed in Table 1). But by the end of the fifth year (60 months), the well is still producing about 93 Mb/d. Even after 300 months (25 years) the well is still expected to be producing 36 Mb/d.

Table 1 – Production Decline Rates; Source: RBN

The red line in Figure 6 is cumulative production over the life of the well. Because of the high IP rate the cumulative production builds quickly in the early years then continues to grow at a slower rate over the entire life of the well, eventually reaching an EUR of about 700 Mbbls (cumulative production in year 25). Almost half of the well’s EUR is produced in the first five years. From an economic perspective, this front-end loaded cash flow is good news. In effect, the producer’s well costs are recovered sooner, which improves the discounted cash flow rate of return (IRR) for the well.

Ideally producers want a high initial rate of production (IP) and a slow rate of decline, so that they can get as much of the well’s cash flow in the early years as possible (this greatly improves the well’s net present value), so that revenues don’t fall off a cliff soon thereafter.



3.4 RBN Production Economics Model Analysis

RBN’s IRR analysis was produced by running published well datasets with values for the seven inputs described above through our spreadsheet model in different price scenarios We use a variety of published sources for the data including investor presentations and analyst reports. Our goal is to include a range of input values for different wells from multiple sources for each basin and in some cases for wells having different economics to do with transportation or commodity prices within basins. Each set of well inputs is categorized as being oil, gas or NGL directed and identified with a particular basin or sub-basin. The summary scenario IRR and breakeven analysis in Section 4 is based on aggregated data for each basin category, calculated by averaging multiple datasets to identify a typical well.

3.4.1 Decline Rates and Decline Curves

The decline rate inputs to our model are monthly or annual decline curve percentages provided by our various data sources. We apply a smoothing technique called the “Arps” curve to these decline rates to produce smooth decline curves. A mining engineer named J.J. Arps in his 1945 paper “Analysis of Decline Curves” developed this method. Effectively the Arps equation fits a hyperbolic curve to a series of decline rates to achieve a curve generally representative of actual well declines.

3.4.2 Estimated Ultimate Recovery

The EUR is an estimate of the total volume of hydrocarbons that can be recovered over the well life. The EUR is simply the cumulative production forecast for the well and in the RBN model is calculated using decline rates and assuming a “standard” 25-year well life. For a multiple commodity well, we calculate the EUR for each commodity.

The following cost and revenue inputs and assumptions are supplied to the model for each well case to produce RBN’ IRR and breakeven analysis:

3.4.3 Cost Inputs

Drilling and Completion Cost: the total cost of drilling and completion

Royalty Interest: This is an agreed upon percentage of the gross production revenue paid to the owner of the mineral rights. The royalty interest varies according to lease terms.

Discount Factor: The discount factor is the interest rate used to calculate the cumulative Discounted Cash Flow for all three commodities: oil, natural gas and NGLs. The sum of the discounted cash flows is the net present value (NPV). The model calculates the value of the discount factor when the NPV is zero as the internal rate of return (IRR), or discounted cash flow rate of return. Theoretically the discount factor represents a company’s internal cost of capital. We set the discount rate in the model to 10% because operators often calculate a well’s break-even price on a before tax basis using a flat 10% discount rate. This facilitates an “apples to apples” comparison both between wells and across basins.

Production Taxes (%): the production tax is levied on the final sale price of the oil and gas at the wellhead. Production taxes apply to net revenue less royalty payments.

Operating Costs: in $/Bbl for oil and liquids or $/Mcf for gas. Variable costs associated with the production of oil, gas and the processing cost for NGL’s.

Operating Cost Escalator (%/yr): expected annual escalator for operating costs defined above. The escalator is assumed to be zero in our analysis



3.4.4 Production Inputs

Initial Production [Oil/Gas/NGL]: the first year’s daily production rate (measuring volume in b/d for oil and NGLs, Mcf/d for gas). Production is multiplied by the assumed commodity price to calculate gross revenue. After the first year, production is calculated using the production decline rate.

Gas GPM content (Gal/Mcf): the typical volume of gas liquids extracted from wet gas at a processing plant for a given well.

NGL Production Volumes: The IP rate and decline curve inputs for natural gas are used to compute gross gas production. Then the liquids content of the gas (GPM) is used to compute the NGL volumes. For example, using a value of 6.5 GPM value and a 1100 Mcf/d IP rate for gas, the initial production rate for NGLs is calculated as 1100*6.5/42=170.24 (where 42 is the number of gallons in a barrel).

Shrinkage: When NGLs are extracted in a processing plant, the volume of gas remaining is naturally going to be less than the original wellhead production. The model computes shrinkage based on the percentage mix of NGL products.

3.4.5 Commodity Price Inputs

Crude Prices and Discounts: crude prices for each well used in our IRR and breakeven analysis have three components. The first is the Cushing WTI benchmark price – in our analysis of pricing scenarios this is the default crude price used for each well (e.g. $90/Bbl, $75/Bbl, $60/Bbl or $45/Bbl). There are also two crude discount variables that can be assigned a value for each well analyzed. The first is quality – e.g. in the Eagle Ford some crude is actually condensate that is typically discounted by refiners who do not value the lighter components in condensate. The second discount component is transport cost to market - typically borne by producers. The transport costs reduce producer crude netbacks (a netback is the crude sales price less transportation costs).

We include the two crude price discount components in our analysis in order to calculate IRRs for both “actual” crude values at the wellhead (default crude price less quality and transport components) and the WTI equivalent price (just the default crude price). Calculating a WTI equivalent IRR allows direct comparison of well performance between basins and an easy reference to WTI - the U.S. benchmark crude price.

Natural Gas Price Discounts: natural gas prices are assumed by default to equal the benchmark CME NYMEX Henry Hub futures price. In a similar way to that explained above for crude we also include price discounts for natural gas. Gas price discounts represent typical basis differentials that represent the price spread between the nearest gas trading hub price point to the well and Henry Hub, LA. Each well producing gas in our analysis is assigned a gas trading hub and each hub has an assigned discount value equal to the most recent yearly average basis spread to Henry. The gas price discount factor is subtracted from the scenario price (e.g. $4.50/MMBtu, $4.00/MMBtu etc.) for each well when calculating IRR’s.

Marcellus and Utica Natural Gas: as a general rule in the model, because they are based on nearby gas trading hubs, all the wells in a gas play use the same basis discount. There is one important exception to this assumption. Currently there is a wide disparity in basis

1,100 MCF 1 day

6.5 gallons1 MCF

1 barrel 42 gallons

170.24 barrelsday X X = =



differentials in the Marcellus and Utica regions, depending on availability of take-away capacity. In some areas of constrained take-away capacity, basis has been very wide with corresponding low natural gas prices. Other areas, generally those further west, have not been subject to such wide differentials. Furthermore, some producers have acquired pipeline capacity to move their gas from the constrained areas to the unconstrained areas. Thus there is a big price difference between natural gas production subject to wide differentials and production that is not. For that reason, two natural gas cases are calculated in the region, one based on the price at Columbia Gas TCO and the other based on the Dominion South trading hub. Dominion South, in West Virginia on the Dominion Transmission (DTI) pipeline system, is usually subject to significant take-away constraints, and as a result, prices at Dominion South (DOM) trade well below Henry Hub. In contrast the Columbia Gas TCO pool hub (TCO) has the capacity to replace incoming supplies from the southeast (on Columbia Gulf) with Marcellus gas. The result is that TCO is less congested than DOM and gas prices at TCO are typically higher by more than $1/MMBtu.

To reflect the fact that these two pricing hubs are mismatched, we split Utica and Marcellus well analysis into separate categories for our IRR analysis – with wells associated with TCO pricing having a lower gas price discount.

NGL to Crude Ratios in the Northeast: as explained above, we use a lower NGL ratio to crude (29%) for liquids plays in the Marcellus and Utica because the latter produce a lighter slate of NGLs and are subject to NGL pricing discounts, particularly during the summer season. For liquids plays outside the Northeast we use a 37% NGL to crude ratio.

3.4.6 Model Outputs

Cash Flows: are calculated for each commodity over the 25-year assumed life of the well by multiplying annual production volumes by the net commodity price (price less discounts and transport) and subtracting the variable operating costs and taxes.

Discounted Cash Flows: using the annual cash flows and the discount factor the model calculates a discounted cash flow for the well. Table 3 shows the discounted cash flow calculation results for a well that cost $7.5 million to drill and complete (investment cost – cell B17). Cash flows for each of the three hydrocarbon products are summed with total investment costs to yield annual cash flows (column B in Table 3) and cumulative cash flows (column C in Table 3). Discounted cash flows are then computed using the 10% discount factor (column D in Table 3).

Table 3 – Cash Flows and Discounted Cash Flows; Source: RBN



Net Present Value: the discounted cash flow (DCF) for a well is the sum of the discounted cash flows (column E in Table 3). The sum of the discounted cash flows is also known as the Net Present Value (NPV).

Internal Rate of Return: the Discounted Internal Rate of Return (IRR) is calculated using the ExcelTM function =IRR() to calculate the rate which discounts the series of before tax net cash flows (column E in Table 3) to zero. The calculated IRR represents the rate of return a producer can expect for a well with the given input characteristics.

Breakeven Price: for a well is calculated by reducing the input value for the crude price (for example by using the ExcelTM solver function or by trial-and-error), until the rate of return is zero. At that price the DCF will pay back the investment exactly over the 25-year well life. The breakeven price can only be calculated for one commodity at a time – meaning that the price of natural gas must remain static when calculating a crude oil breakeven. In our analysis we calculated breakeven values for crude at various natural gas prices. (NGLs are priced as a percentage of crude.)

3.5 RBN IRR and Breakeven Analysis

3.5.1 Coverage and Categorization

For our analysis we used well data from the shale basins and plays listed in Table 4.

Table 4 – Basin Coverage; Source: RBN

As stated earlier we analyzed data from a range of wells for each of these basins and aggregated the results to provide summary values for the categories in Table 4 – oil, liquids (NGLs) and natural gas. Wells are placed into these categories based on the commodity that provides the greatest contribution to total well revenues. For example, natural gas plays are usually the easiest to categorize as such since they do not produce meaningful liquids outputs. It is more difficult to determine whether a well is primarily producing oil or NGLs since they both typically produce both. For our analysis we categorized wells in the liquids (NGL) category if more than 40% of the first year’s output was in the form of NGLs. The exception to this rule was wells identified as located in the liquids (wet gas) window of the Eagle Ford in South Texas.

As explained above Marcellus and Utica liquids and gas wells are categorized as “DOM” or “TCO” depending on their natural gas market price delivery hub.

For each of the fourteen plays used in our analysis (shown in Table 4) we aggregated results reflecting representative wells. These representative wells were not simple averages of all well results. Rather we focused on wells drilled over the past two years which appeared to be representative – in terms of cost and well performance – of the typical well drilled in each play. We eliminated outliers from the analysis to arrive at a representative sample across multiple sources.



3.5.2 Premises

Table 5 lists the most important input variables used for each play – more detail on each of these below. We provide this level of data to improve the reader’s understanding of how to interpret our IRR and breakeven results.

Table 5 – Analysis Premises; Source: RBN

Drilling and Completion Costs: half-cycle costs as described above that exclude certain costs such as exploration and leasing. Per well drilling and completion costs range from a low of $3.0 million in the Piceance Basin to $10 million in the Utica. Note that these costs are based on inputs derived from wells drilled before the crude price crash and consequently are biased high. These costs are coming down quickly as services providers reduce fees to remain competitive in today’s low crude price environment.

Oil IP Rate: crude oil initial production rate in barrels of oil per day. Gas-only and NGL-only wells do not have oil IPs. Note that these IPs are in some cases considerably above the average well in each play. For example, we use an IP of 700 Mb/d in the Bakken when the average well over the past two years may be 200 Mb/d below that level. In this analysis we are focused on the wells that are targeted by producers today, not necessarily historical experience.

Oil Price Differential: The differential applied to WTI prices to reduce prices to the field level. The higher differential for Bakken crude is reflective of a geographic differential while the differentials for the Eagle Ford is reflective of a quality differential (about half of the crude oil is priced as condensate).

Oil Decline: This is the first year decline rate applied to the oil stream. Like other factors, these decline rates are for representative wells and vary significantly within basins and from well to well.

Gas IP Rate: natural gas initial production rate in Mcf/d.

Oil Plays

Drilling and

Completion

Costs (MM)

Oil IP

Rate First

30

(Bbl/day)

Oil Price

Differential

($/bbl)

Oil

Decline

Y1

Gas IP Rate

First 30

(Mcf/Day)

Gas Price

Differential

($/Mcf)

Gas

Decline

Y1

GPM

Content

Anadarko 3.0$ 200 (1.50) 57% 600 ‐0.09 63% 4.4

Eagle Ford 8.0$ 750 (4.00) 73% 1,000 ‐0.01 75% 4.2

Permian 7.0$ 500 (2.50) 73% 1,200 ‐0.03 70% 4.6

Bakken 9.0$ 700 (6.50) 68% 450 ‐0.04 73% 6.3

Niobrara 4.4$ 325 (1.50) 79% 800 ‐0.03 79% 4.2

Liquids Plays

Utica 10.0$ 0 (1.50) 50% 6,000 * 50% 8.2

Eagle Ford 8.0$ 300 (6.00) 71% 4,000 ‐0.01 71% 5.2

Granite Wash 7.0$ 100 (1.50) 74% 6,000 ‐0.09 74% 5.2

Marcellus 7.0$ 0 (1.50) 53% 5,000 * 53% 5.5

Gas Plays

Marcellus 5.5$ NA NA NA 8,000 * 65% NA

Utica 10.0$ NA NA NA 9,000 * 52% NA

Haynesville 8.0$ NA NA NA 12,000 0.00 70% NA

Fayetteville 2.7$ NA NA NA 2,800 ‐0.09 69% NA

Piceance 1.7$ NA NA NA 1,700 ‐0.03 72% NA

* Varies depending on location and take‐away capacity



Gas Price Differential: These differentials are based on the average basis between these points and Henry Hub during 2014.

Gas Decline: This is the first year decline rate applied to the gas stream.

GPM Content: This is the assumed liquids content of the gas as measured by gallons per thousand cubic feet (GPM). NGL volume is developed using the gas production rate and the gas production rate is reduced by NGL shrinkage. The GPM for dry gas plays is omitted since it is assumed that no NGLs are extracted from the dry gas plays.

Typical Wells and Sweet Spot Wells: We then extracted from each typical well set a super set of “sweet spot” wells having the highest IP rates that produce the highest IRRs. We used these wells to identify sweet spot well characteristics.

Section 4 – IRR and Breakeven Analysis Results

4.1 Then and Now

We start with overall results from our analysis beginning with two overviews of typical IRRs seen in oil, wet gas (NGLs) and dry gas plays in different price scenarios. The first of these scenarios is with oil at $90/Bbl and gas at $3.75/MMbtu as experienced in the fall of 2014. We compared those results to the situation in January 2015 with oil at about $45/Bbl and gas at about $3/MMBtu. Figure 7 shows typical IRRs for the fall of 2014. Black circles are oil plays, red circles are dry gas and green circles are wet gas plays.

With oil at $90/Bbl the oil plays easily show the best returns with the Anadarko at 41% followed by Permian at 40%, Bakken at 39%, Eagle Ford at 40% and Niobrara at 37%. Next highest returns are for the wet gas NGL plays with the Eagle Ford yielding 25% IRR and the Granite Wash 23%. In the Utica and Marcellus recall that we provide separate scenarios for dry gas and liquids based on market delivery to Dominion South Point (where congestion is increasing market price discounts to Henry Hub thus reducing IRRs) and Columbia Gas TCO where there is less congestion and price discounts are lower. Typical wet gas wells delivering to the Utica TCO hub produce 32% IRRs compared to 24% for Dominion South. In the Marcellus the wet gas typical IRRs delivered to TCO are 22% and to Dominion South 13%. Finally typical dry gas returns at $3.75/MMBtu (oil prices are not applicable to dry gas wells) are 6% for the Fayetteville and 5% for the Haynesville and -2% for the Piceance. Far higher IP rates in the Utica and Marcellus dry gas plays produce higher IRRs for wells delivering into TCO – at 16% for Marcellus and 15% for Utica. These higher IRRs are reduced considerably by lower market prices for wells delivering to Dominion South that have an IRR of -1% in the Marcellus and 1% in the Utica. Note that these returns, while attractive, still are not as good as the returns seen during the summer of 2014 when crude oil was above $100/Bbl and natural gas exceeded $4.50/MMbtu.



Figure 7 – Fall 2014 IRR Results; Source: RBN

Our second scenarios are with oil at $45/Bbl and gas at $3.00/MMbtu as experienced during much of January 2015 (see Figure 8). With oil at $45/Bbl and gas at $3/MMBtu pretty much all the plays show negative IRRs except for three oil basins - the Anadarko at 3% (down from 41% at $90/Bbl), the Permian at 3% (down from 40%), and the Bakken at 1% (down from 39%). Eagle Ford oil is down to breakeven (0%) from 40% at $90/Bbl oil and the Niobrara is also at breakeven (down from 37%). All the wet gas NGL plays are underwater in this scenario with the Eagle Ford producing -3% IRR (down from 24%) and the Granite Wash -2% (down from 23%). Typical wet gas wells delivering to the Utica TCO hub produce 1% (down from 32%) IRRs compared to -4% (down from 24%) for Dominion South. In the Marcellus the wet gas typical IRRs delivered to TCO are -2% (down from 22%) and to Dominion South -9% (down from 13%). Typical dry gas returns at $3.00/MMBtu are -8% (down from 2%) for the Piceance, -2% (down from 6%) for the Fayetteville and -4% (down from 5%) for the Haynesville. In the Utica and Marcellus dry gas plays produce higher IRRs for wells delivering into TCO at 3% (down from 16%) for Marcellus and 4% (down from 15%) for Utica. Those just positive IRRs are turned negative by lower market prices at Dominion South with IRRs of -11% (down from -1%) in the Marcellus and -8% (down from 1%) in the Utica.



Figure 8 – January 2015 IRR Results; Source: RBN

The unsurprising take-away from this analysis is that from Fall 2014 to January 2015, unhedged producer returns have declined from quite healthy levels in most plays down to marginal or negative returns today. The representative well in most plays is under water, with marginal profitability demonstrated in only the very best plays. Clearly returns are quite sensitive to prices.

4.2 Typical Oil Plays

To show exactly how sensitive returns are to prices, we next summarize representative IRR results for oil plays at different price levels.

Table 6 – Oil Play Sensitivity to Oil Prices; Source: RBN

Table 6 provides a summary of the IRR analysis results for oil plays at 4 different crude prices: $90/Bbl, $75/Bbl, $60/Bbl and $45/Bbl in columns 2 through 5 respectively. All of these scenarios used an NGL ratio of 37% and assume a $3/MMBtu price for gas at Henry Hub. To the right of the IRR percentages are the same input factors as described above: drilling and completion costs in millions of dollars per well, the oil IP rate for the 1st 30 days, oil price differentials to WTI (transport and quality differentials by basin) as well as the first year production decline rate. The



top oil plays all produce both natural gas and NGLs, so the final columns in the table indicate gas IP rate, gas price differential to Henry and gas year 1 production decline percentage. The final column indicates gas liquids GPM. All of these oil plays produce IRRs just below 40% at $90/Bbl oil, around 25% at $75/Bbl oil and around 13% for $60/Bbl oil. At $45/Bbl typical Eagle Ford and Niobrara wells are at breakeven (0% IRR), the Anadarko and Permian return 3% and the Bakken 1% - suggesting that if oil prices stay at that level for a long period, shale drilling in these plays will eventually be reduced significantly.

Note that regardless of the wide variances in well cost, the IRRs are clustered rather tightly. For example, the IRR range for the $90/bbl crude case is from a low of 36% to a high of 39%. We believe this is basically a manifestation of ‘natural selection’. In other words, in the various plays producers only drill wells that generate attractive returns. In basins with higher drilling and completion costs that means wells need to have higher IP rates.

Figure 9 – IRR Sensitivity to Oil Prices; Source: RBN

Also note that using our modeling methodology, the sensitivity results are linear. For example, Figure 9 shows average IRRs for typical wells in all crude plays (left axis in %) plotted against crude price (bottom axis, $/Bbl) with gas prices as $3/MMbtu. Since the only input variable changing is oil price, the IRR has a linear relationship to the crude price.

4.3 Sweet Spots in Oil Plays

As we have pointed out, our typical wells are representative of each basin as a whole. We also identified those wells within basins with higher oil IP rates that produce optimum IRRs. These sweet spot results are summarized in Table 7. As for the typical well results in Table 6 we present four price scenarios for the sweet spot wells – at $90, $75, $60 and $45/Bbl oil respectively. You can compare the oil IP rates in column 6 of Table 6 to the same numbers in Table 7 to see how much better the sweet spot wells perform. The rightmost column in Table 7 indicates the percentage spread between IRRs for typical and sweet spot wells at $60/Bbl oil. The data shows that IRRs improved the most for sweet spot wells in the Permian Basin – up 24% from the 14% typical well with IP oil output increasing from 500 to 800 b/d. Next best improvement was in the



Anadarko with the IRR improved by 20% in sweet spot wells to 34%, followed by the Niobrara- up 10% from 11% at $60/Bbl oil. Eagle Ford typical IRRs at 12% increased to 21% in the sweet spots and Bakken sweet spots produced 6% higher IRRs than the 12% in typical wells.

Table 7 – Oil Sweet Spot Well IRRs; Source: RBN

The oil play sweet spot analysis illustrates that at $60/Bbl oil, producers can find better IRR’s by concentrating on sweet spots in the plays – particularly in the Permian, Niobrara and Anadarko. And of course these sweet spot plays produce even better IRRs at higher oil prices.

4.4 Breakeven Analysis of Crude Plays

Table 8 – Breakeven Crude Prices; Source: RBN

The data in Table 8 shows RBN’s breakeven analysis for the major crude plays we included in the study. As stated earlier, the breakeven is calculated by using the ExcelTM solver function to identify the crude price at which the IRR is 0% - indicating the price at which a producer would simply get their money back (including a standard 10% cost of capital) on the drilling investment – over the 25 year life of the well. The analysis assumes gas prices are $3/MMBtu. For each play we calculated four breakeven prices. Column 1 in Table 8 is the breakeven for a typical well in each play with the crude price including differentials to WTI based on crude quality and

Oil Plays ‐ Sweet

Spot $90 Crude $75 Crude $60 Crude $45 Crude

Oil IP

Rate First

30

(Bbl/day)

Average

to Sweet

Spot

Spread

($60)

Anadarko 73% 53% 34% 16% 300 20%

Eagle Ford 57% 39% 21% 7% 950 9%

Permian 79% 58% 38% 19% 800 24%

Bakken 49% 33% 18% 5% 800 6%

Niobrara 52% 36% 21% 11% 400 10%



transportation (see Table 6). These values reinforce the IRR results by showing how close to breakeven typical wells are in these plays at $45/Bbl crude. In column 2 we show the breakeven values (including differentials to WTI) for our sweet spot wells in the plays. As expected, these breakeven crude prices are lower than typical wells – the actual spread is indicated in column 3. In columns 4 and 5 we list the breakeven equivalent WTI values for typical and sweet spot wells respectively.

Figure 10 – Typical Well Breakeven vs Sweet Spot Breakeven by Basin; Source: RBN

While the breakevens for typical wells are unattractive at $45/Bbl oil, the sweet spots will continue to provide a return on investment at that price. This indicates that producers who have the available lease acreage can hunker down and concentrate on sweet spots even with prices at recent lows near $45/Bbl. It should also be noted that the sweet spot wells have higher IP rates and will therefore actually increase production compared to typical wells. Although producers may decide to wait on better prices to drill in sweet spots in order to maximize their IRR, the need for cash flow in the short term could dictate migration to the sweet spots. Figure 10 shows the breakeven data by play for typical well values (red bars) and sweet spots (blue bars).

Typical IRR and breakeven analysis for specific wells is based on crude and natural gas prices realized at the wellhead. Our analysis sticks to this convention but by isolating the price and quality differentials to benchmarks we are able to provide IRRs and breakevens for oil plays on a WTI basis. While this is less meaningful to the individual producer in a particular basin it is valuable for comparison across basins and makes it easier to understand the impact of changes in the far more visible WTI price on the viability of drilling in particular basins. The WTI breakevens for typical wells in Table 8 show that for the Eagle Ford and the Bakken, WTI needs to be closer to $50/Bbl for breakeven and in the case of the Bakken even sweet spot wells barely breakeven at $45/Bbl WTI prices.

4.5 Gas Liquids Plays – Alternative Crude Price Scenarios

Table 9 shows a summary of typical IRR results for gas liquids plays at different crude price levels with the Henry Hub natural gas price pegged at $3/MMBtu.



Table 9 – Gas Liquids Plays Sensitivity to Crude Prices; Source: RBN

As with the crude play analysis (Table 6) we provide a summary of the IRR analysis results for wet gas/NGL plays at 4 different crude prices: $90/Bbl, $75/Bbl, $60/Bbl and $45/Bbl in columns 2 through 5 respectively. There are 6 liquids play scenarios in the table – recall that liquids plays are defined by more than 40% of first year revenues coming from NGLs – except for the Eagle Ford where we selected wells in the wet gas window of the play. For the Eagle Ford and Granite Wash plays our assumption is that NGL production is valued at 37% of the crude price. For the Northeast Utica and Marcellus plays we assumed a lower NGL value of 29% of crude because of the higher ethane content in NGL production from these plays combined with lower realized prices due to oversupply problems in the region, particularly during the summer.

The IRRs shown represent typical wells for each play. To the right of the IRR percentages for each crude price level are the input factors referenced earlier, including drilling and completion costs in millions of dollars per well. For the Eagle Ford and Granite Wash there is crude production so we provide the oil IP rate for the 1st 30 days, oil price differentials to WTI (transport and quality differentials by basin) as well as the first year oil production decline rate. These liquids plays produce both natural gas and NGLs, so the final columns in the table indicate gas IP rate, the gas price differential to Henry Hub, gas year 1 production decline percentage, and gas liquids GPM.

First consider the IRR results for the Eagle Ford and Granite Wash. Eagle Ford IRR’s are 21% at $90/Bbl crude falling to 4% at $60/Bbl crude and -3% at $45/Bbl. Results for the Granite Wash are similar – starting at 18% for $90 oil, down to 4% at $60 and underwater at -2% for $45/Bbl crude. With today’s lower gas liquids prices compared to crude, the IRRs for liquids plays are predictably lower than for crude plays. Comparing the results for the Eagle Ford oil versus liquids provides a direct comparison indicating that typical Eagle Ford oil wells produce nearly double the IRR for representative liquids wells at $90 and $75/Bbl crude and three times the return at $60/Bbl. At $45/Bbl crude all our liquids play scenarios are underwater with negative IRRs except for Utica TCO at 1%.

Turning to the Northeast plays, Utica TCO liquids wells are the top performers in the category with positive returns at all crude price levels. Remember that TCO well liquid output is only valued at 29% of crude prices (versus 39% for Eagle Ford or Granite Wash), so Utica TCO’s top billing illustrates how prolific the liquids output is in this region. In contrast, Marcellus liquids wells fare worst in this category with TCO market delivery producing a reasonable 15% IRR at $90/Bbl down to -2% at $45/Bbl oil and DOM market delivery producing a meager 7% IRR at $90/Bbl down to -9% at $45/Bbl.

4.6 Gas Liquids Plays – Gas Price Scenarios

To better understand the sensitivity of IRRs from liquids plays to gas prices as well as crude we provide a summary of results for 4 different natural gas prices at both $60/Bbl crude and $45/Bbl crude in Table 10. The data indicates that typical wells in liquids plays are more sensitive to lower crude prices than they are to falling gas prices, since at $3.75/MMBtu gas prices (yellow columns)



most plays have very low or negative IRRs at $45/Bbl oil and more reasonable IRRs (except for Marcellus DOM) at $60/Bbl oil. Higher gas prices really do not help in a low oil price environment – for example at $45/Bbl oil the liquids plays produce dismal returns even at $4.50/MMBtu gas prices.

Table 10 – Gas Liquids Plays Sensitivity to Crude Prices; Source: RBN

4.6.1 Crude and Liquids Sensitivity to Oil Prices

Figure 11 is a summary chart showing IRR sensitivity to different oil prices for both the oil plays (left side of the chart) and the gas liquids (right side) with gas prices at $3/MMBtu.

Figure 11 – IRR Sensitivity to Oil Price; Source: RBN

Higher oil prices ($90/Bbl – green bars) produce better IRR rates in oil plays than liquids plays and that pattern is repeated at $75/Bbl oil as well as $60/Bbl oil. Predictably the picture looks worse at $45/Bbl with the typical wells in oil plays at or just above breakeven (0% IRR) and liquids plays are underwater except for the Utica TCO.

4.6.2 Dry Gas Plays – Gas Price Sensitivities

Table 11 summarizes IRRs for typical wells in dry gas plays at four different gas price levels - $4.50/MMBtu (grey column), $3.75/MMBtu (yellow), $3.00/MMBtu (green) and $2.25/MMBtu



(purple). Since dry gas plays produce no liquids, crude prices have no bearing on well performance. In addition to IRRs at different price levels Table 11 repeats the model input data reviewed earlier, showing drilling costs per well, gas IP rate, gas price differentials to Henry Hub and the first year gas production decline rate.

Table 11 – Gas Play Sensitivity to Gas Prices; Source: RBN

The IRRs for these gas plays are predictably dependent on the gas price with the majority producing positive IRRs at $3.75 and $4.50/MMBtu. If gas prices drop to $2.25/MMBtu then all these plays would be underwater with negative IRRs. Aside from commodity price for a dry gas well the drilling and completion cost plays a big part in performance with typical wells in the Fayetteville and Piceance having lower representative per well costs of $2.7 MM and $1.7 MM respectively. Higher gas IP rates in the Utica and Haynesville are offset by higher representative well costs of $10 MM and $8 MM respectively. Marcellus TCO wells produce the best IRRs from a relatively low $5MM well cost and high IP rate (8000 Mcf/d). The Utica and Marcellus DOM wells delivering into Dominion South are penalized by a $1/Mcf price differential (discount) to Henry Hub. At $2.25/MMBtu gas that differential is squeezed to only $.25/MMbtu based on an expectation that outright prices will decline, limiting the absolute floor for prices in the region to no less than $2.00/MMbtu.

4.6.3 Gas and Liquids Sensitivity to Gas Prices

The chart in Figure 12 is a summary of IRR sensitivities for both liquids (left side) and dry gas (right side) plays at different gas price levels. All of the scenarios in this chart are at $60/Bbl oil prices – only impacting the liquids (left side of the chart). Because the gas price is the only parameter changed in this chart, higher (green bars) and lower (purple bars) gas prices have a bigger impact on dry gas plays (right side of the chart) than on the liquids.



Figure 12 – Gas and Liquids Sensitivity to Gas Prices; Source: RBN

Conclusions The more than 50% fall in crude prices since June 2014 and 30% fall in natural gas since

November 2014 have crushed producer internal rates of return (IRRs) for typical wells in U.S. shale plays.

Analysis of IRRs and crude breakevens provides insight into what may happen to production going forward as producers scramble to respond

Continued growth in shale production is related to IRR economics, but with several caveats that affect producers including high IRRs in drilling sweet spots, the impact of hedging, HBP, lower services costs and the number of hold over completions from last year.

This report includes results from IRR and breakeven sensitivity analysis by basin and commodity using the RBN Production Economics model and input well data from a variety of sources

Coming up with representative input variables for the model is as much art as science but the main goal is to understand how the numbers relate to each other. Most analysts make you guess what the input variables are, so you really don’t know what you are looking at. In the pages above, we lay it out for you so you can make your own judgments about whether or not our data is representative.

Expected lower drilling, completion and operating costs due to budget pressure on services providers are not factored into this analysis yet. Costs may be 25% lower in our next iteration and that will improve these returns.

Our conclusions are hardly surprising - crude oil wells perform better than gas and natural gas liquids (NGLs) except in the direst crude price scenarios. The lower oil and gas prices get - the worse the return. Sweet spots make a difference – sometimes a big difference.

Producer Breakevens

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