Recalibrating the Bakken- Seeking Opportunity in Recapitalization of The King of Oil Shales

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1 Recalibrating the Bakken- Seeking Opportunity in Recapitalization of The King of Oil Shales 1 P a g e

2 Table of Contents Page Executive Summary.. 3 About this Report. 6 Part 1 o Introduction- Why the Bakken?.. 8 o What is a DUC and what is its Value o Bakken Geological Overview. 12 o Bakken Resource Size. 13 o Bakken Geological Areas; The Best of the Bakken 14 The Worst of the Bakken. 19 Part 2- Summary of Several Bakken Focused, Public Companies o Continental Resources..23 o Earthstone Energy.26 o Newfield Exploration 28 o Oasis Petroleum.32 o SM Energy 35 o WPX Energy 38 2 P a g e

3 Executive Summary The Bakken oil play constitutes one of the largest, and most significant, oil developments in the U.S. in the past 40 years and one of the first unconventional oil resource plays to be exploited in the US. A few years ago the Bakken was considered The King of Shale Oil but where is it now? The Bakken is a Late Devonian to Early Mississippian age formation in the Williston Basin, covering the states of North Dakota and Montana and extending into the southern part of Saskatchewan. The generative part of the basin is situated largely in North Dakota over an area of ~150,000 square miles. It is the generative part of the basin that defines the economic Bakken Petroleum System. Exploration of the Williston basin began in the 1950 s, but it was not until 2006 did horizontal drilling activity begin to produce significant volumes of Bakken oil. From early 2006, Bakken production grew from ~ 10,000 boe/d and peaked in July 2015 at ~1,150,000 bo/d. However, as a result of low oil prices and diminished low drilling activity, production has declined to ~ 977,000 by July Cumulative production from the North Dakota Bakken is ~1.6 Billion barrels of oil. Many North Dakota geologists believe the Bakken will ultimately produce between Billion barrels of oil. Even the traditionally conservative USGS (2013) has recovery from the Bakken Petroleum System at 7.5 B, almost 6 Billion more than has been produced to date. From a resource perspective, the Bakken has a long life ahead. Over the past 5 years, economic Bakken resources have become much more concentrated. The high productivity core area has become smaller and yet the resource size has become much larger. And this is because the Three Forks formation, immediately underlying the Bakken, has proven to be commercial over much of the new core area. And in some parts, there now are 2-3 vertically stacked resource zones in the Bakken and Three Forks. Over the past year, drilling has effectively been confined to four counties in North Dakota; McKenzie, Williams, Mountrail and Dunn. Geological factors such as over pressure, fracturing, saturation, reservoir development are some of the subsurface factors that drive high productivity wells in these counties. Over much of these areas, D&C well economics are positive below $50 oil price, and over some areas breakeven costs are below $40. Many operators in the new Bakken core, like Continental Resources, have said they will increase drilling activity at above $55-60 oil price. However, in other parts of the basin, such as Divide and Stark Counties, N Dakota and eastern Montana, less favorable geological characteristics contribute to lower productivity wells and much higher breakeven D&C costs. We expect some of these areas will have breakeven oil price above $65 oil. Operators in these areas with drilling commitments are challenged with poorer capital efficiencies, faced with higher PUD economic impairments, higher erosion of PUD s due to the SEC s 5-year PUD rule, higher erosion of borrowing base and potential liquidity issues. One other game changer in the Bakken has been dramatically improved financial efficiencies because of capital cost reduction and improvement in well completion design. On the later, many operators are now using high intensity completions that have 10,000 laterals, 50 stage fracs and utilize up to 13 MM tons of sand. Some are also using slick water as 3 P a g e

4 completion fluid. The improvements in capital efficiencies have been remarkable. Many operators have reduced D&C well costs by up to 45% while increasing EUR s by up to 60%. In the best Bakken areas, in the Nesson Trend and Eastern Oil window, M Bakken type curve EUR s range between M Boe. These EUR s are expect to have a sub $ 40 breakeven price. These areas constitute the new Bakken core. These are the best Bakken rocks. In the new Bakken, it s now about the best rock and the best completion. And it is working, very well. The King is not dead. However, Bakken resource exploitation expansion has come at a huge price. From 2011-early 2014, global oil prices were over $100/bbl. During this period Bakken production grew from ~275,000 bo/d to over 1,000,000 bo/d. At its drilling peak, WoodMac was forecasting $15 Billion for 2014 Bakken drilling and completions. In Dec 2014, Whiting Petroleum bought Bakken producer, Kodiak, for $6 Billion including $ 2.2 Billion of debt. This massive production buildout left the Bakken has many operators burdened by high debt. And as oil prices crumbled in 2014, high leveraged Bakken producers began to get squeezed. For some, the cost of servicing this debt became very high relative to cash flow generated. Others expanded into lower productivity Bakken areas and had no ability to increase economic production or monetize the property to pay down debt. Those that did not become insolvent in 2015, prolonged low oil prices in 2016 have led to a continued struggle with debt and liquidity this year. Since 2014, low drilling activity resulted in erosion of booked PUD locations that are beyond the 5-year period the SEC allows companies to carry PUD s. Also, many companies in lower productivity areas of the play are facing economic impairments on their PUD bookings. Both the 5-year rule and PUD impairments have considerably clouded the financial picture for several Bakken producers. High debt continues to be an issues with many early stage Bakken operators. Many funded Bakken expansion with debt and continue to face challenges this year. These companies may represent interesting hedges to balance more attractive Bakken long position. Others have used good Bakken acreage as optionality to transition into other growth assets (i.e. Permian basin, Anadarko basin STACK play). These companies can use these higher valued Bakken acreage as trading chips to transition into even higher capital efficiency areas. Other Bakken operators with large resource inventories in the best Bakken areas, have a different outlook. These are positioned to become the new leaders of a large Bakken resource that is come more concentrated and stacked vertically in core areas. After the last crash in 2008, which was far less intense and duration than the 2014 crash, the survivors had massive stick recoveries in the subsequent two years. Bakken producers also showed attractive share price bounces, including; Pioneer >600% recovery Abraxas > 700% recovery Northern Oil and Gas >1000% recovery 4 P a g e

5 In the new Bakken core, we believe the survivor Bakken companies will show a similar bounce back as oil price rebounds. Who s who in the Bakken? We have analyzed nine, publically traded, Bakken operating companies in this report. Two years ago, all these companies, in various stages of corporate evolution, had key Bakken assets that underpinned their share price valuation. Some have become causalities, some have successfully transitioned to another resource focus, and some are set to be Bakken survivor leaders. However, we have chosen to focus on the survivors and how their Bakken acreage fits with their current corporate strategies. Of the 9 companies, we have identified 6 companies that we believe should be considered as potential investment portfolio additions in a rising oil price scenario. These companies are summarized in Section 2 of the Bakken Report. Disclaimer: I am not an investment advisor and this is not a recommendation to buy or sell a security. I am a geologist, not a CFA. The information and data presented was obtained from company documents and/or public domain sources believed to be reliable, but have not been independently verified. Therefore, the author cannot guarantee their accuracy. Please do your own research and contact a qualified investment advisor. I am not responsible for investment decisions you make. 5 P a g e

6 About This Report; The report was initially prepared for the financial community in late 2016 and has been streamlined for the purpose of providing a sample report for marketing purposes. For those interested in receiving a full report, including review of 2016 Quarterly financial results and more detailed discussion of specific assets, should inquire by at michael@fortitudeenergyconsultants.rocks. The report has be organized into two sections, Part 1, a geological review of the Bakken petroleum system, and Part 2, a summary of six interesting Bakken weighted public companies. Executive Summary Part 1 o Introduction- Why the Bakken? o About this Report o What is a DUC and what is its Value? o Bakken Geological Overview o Bakken Resource Size o Bakken Geological Areas; the Best of the Bakken the Worst of the Bakken Part 2- Summary of Several Bakken Focused, Public Companies o Continental Resources o Earthstone Energy o Newfield Exploration o Oasis Petroleum o SM Energy o WPX Energy This report is presented in bullet point format with the exception of the Executive Summary, Introduction and the Company Summaries in Section 2. Research information was publically available either on open file data bases such as PLS, profession subscriptions (PLS Bakken Report, NatGas Intelligence), corporate presentations, SEC 10K and 10Q Reports, technical publications, and interviews with Denver based Bakken geologists. Within this report, we refer to a Relative Valuation of operating companies. In our valuation we assume the same pricing used at year-end reporting in the 10-K filing. We then apply a risk factor to the net resource inventory of well locations but capped at what a company could drill in a 10-year period. It is intended only to show a relative upside valuation based on a resource inventory. Our Bakken basket is comprised of 10 active Bakken companies that are equally weighted. Our basket is called FORTBAK index (Fortitude Bakken Basket) and is indicated by the green line below. The 10 companies represent a spectrum of company sizes and includes the following companies; Black Ridge Oil & Gas- pure Bakken microcap Conoco (Burlington)- 18 drilling permits in Oct, 4 rigs running in Nov Denbury- 2 drilling permits in Oct 6 P a g e

7 EOG- 1 rig running, 30 Bakken drilling permits in Oct, 10 Hz Permits in Nov Enerplus- 3 drilling permits in Oct, 1 rig running in Nov Hess- 10 drilling permits in Oct, 2 rigs running in Nov Marathon- 2 Bakken drilling permits in Oct Northern Oil and Gas- pure Bakken Play with $1 B market cap QEP- 6 drilling permits in Oct, market cap $4 B Whiting- 4 rigs running, 7 Hz Permits in Nov 7 P a g e

8 Introduction- Why the Bakken? When we think of US oil resource plays, the Bakken formation immediately comes to mind. It is one of the largest oil developments in the U.S. in the past 40 years and one of the first unconventional oil resource plays to be exploited in the US. In the past 10 years, it has become a prolific unconventional oil play. A few years ago, the Bakken was referred to as the King of Oil Shale. But has the Bakken run out of steam, or is there more in the tank? Production commenced from the Bakken in the early 1950 s. However, it wasn t until the advent of horizontal drilling in 2006 did production growth from the Bakken begin. In 2006 Bakken production was under 10,000 bo/d which peaked to ~1,150,000 bo/d in July By July 2016, North Dakota Bakken production had fallen to ~977,000. Cumulative production from the North Dakota Bakken is ~1.6 Billion bo. The amount of oil the Bakken will ultimately produce is a matter of debate. In 2013, the USGS estimated that 7.4 billion bo and 6.7 TCF of natural gas was recoverable from the Bakken Petroleum System (including Three Forks). Harold Hamm, CEO of Continental Resources, believes the play to be much larger and could potentially recover 24 B boe. ND Geological Survey and Oil and Gas Division believes recovery range is 6-30 B bo. Many North Dakota geologists believe the range of recoverable oil is between B boe. It any case, there is a lot of running room left in the Bakken. Over the last 5 years Bakken resources have become larger and the productive area, more concentrated. In 2014, Continental Resources was reporting exploitation strategy of 14 horizontals per/drainage unit in the M Bakken, Three Forks B1, Three Forks B2 and Three Forks B3 intervals. Other operators are beginning to test the potential of the Three Forks Bench 4, which is productive in places. Other operators are also putting up to 4 laterals/drainage unit in Pronghorn sandstone, a member of the Lower Bakken transgressive unit. As a result of these other zones many of the high productivity areas of the Bakken play, some are down spacing from 12 to 16 wells per 1,280 acre spacing unit. Stacked pay zones Middle Bakken and Three Forks reservoir also maybe in communication. Regional fracturing on the Nesson Anticlinal Trend has produced large fractures that may allow communication between all reservoirs in Bakken-Three Forks interval. This is a relatively new concept differing from the original idea that what was generated in the Bakken, stays in the Bakken, implying that migration does NOT play a role in prospect charge. However, now many North Dakota geologists believe there may be a migrated component of Bakken resources. This may be especially so on the Nesson Trend, which has undergone several periods of structural uplift that resulted in Three Forks reservoirs or benches added to the gross rock volume to the oil column. Cost have come down. Rig activity for the past few years has continued to drop YoY and with so many horizontal wells rigs now idle and opportunity is provided drastic cost reduction. Many operators are reporting significantly reduced drilling times, Whiting reduced their drilling time by 53% in the last 4 years. Continental has reduced its drilling and completed from $9 MM in 2012 to the current cost of $6.3 MM. Hess have reduced D&C costs by 25% to ~$5 MM. Many operators are reporting D&C wells costs of ~$6 MM. 8 P a g e

9 Over the past two years, the Bakken theme has become best rock and best completion. This has resulted in dramatic lowering of breakeven costs. The second part of our Bakken theme is best completions. This equates to longer reach laterals, more frac stages and more sand. These are referred to by some as High Intensity Completions and are becoming the operating norm in the Williston basin. These are typically 10,000 laterals, with 50 stage fracs and 5-10 Million tons of sand. In Q2, proppant per average well was 6 million lbs and the average number frac stages per well is now above 40. EOG is the Bakken leader in sand proppant with recently completed wells using as much as 13 million tons of sand. The results have been impressive. Operators are reporting EUR uplifts of between 30-60% at costs still 25-50% below 2014 well costs. Bakken leader, Continental Resources have increased their Bakken Type Curve EUR from 550 MBO in 2014 to 900 MBO in Recent wells have been higher than this. Over the same period Continental have reduced well costs 9 P a g e

10 from $9.8 MM to $6.3 MM. And operational work is continuing improve capital efficiencies. Recently Continental drilled three 15,000-ft-plus laterals with a single drill bit and motor. Hess have reduced D&C well costs in the past 2 years by 25% to ~$5 MM while increasing well productivity. Hess also expects to maintain this well costs even as it transitions to a 50- stage completion design from its previous 35-stage standard. This completion design is expected to increase initial production rates by 15-20%. Companies are also improving efficiencies with completion fluid changes. Continental has shifted to a slick water completion from the previous hybrid completion and are reporting improvements to EUR s of 35-45%. At the 2016 Williston Basin Petroleum Conference (WBPC), Ron Ness, president of the North Dakota Petroleum Council (NDPC) believes that the cost reductions and improved capital efficiencies have made the Bakken a $65/bbl play from an $85/bbl play Several operators in the best areas of the Bakken have upgraded their Type Curve EUR s to over 1 MM Boe/well. Whiting Petroleum, who acreage is concentrated in the high productivity Nesson anticline and Eastern Oil Window play areas, are carrying TC EUR s of 1.55 MM Boe/well. We expect this will have robust economics below $35 oil. Continental believes their acreage on the Nesson Anticline, is one of the premier Bakken areas that have a sub $40 breakeven cost. At the at the Williston Basin Petroleum Conference (WBPC) in Bismarck, ND in May this year, Whiting CEO Jim Volker stated that above $50 oil price initial returns on a Bakken well can be 50%. Once referred to as the King of Oil Shales, the Bakken is still deep in economic resources at $50 oil price. Still one of the most prolific oil resource plays in the US, the Bakken will likely see a renaissance in drilling as the oil price recovery continues through P a g e

11 DUC s- What are DUC s and what is their Value? o o o DUC s stand for Drilled Uncompleted Wells These well have been drilled in the past two years, generally as consequence of rig contracts, but not completed because of low oil prices As of May this year, U.S. onshore operators had accumulated 3,900 DUC horizontal oil wells, with more than 90% of them the major liquids plays According to Natural Gas Intelligence 2016, the DUC inventory includes; Permian Basin with 1,200 wells Permian Basin with 1,200 wells Eagle Ford Shale with ~1,000 wells Bakken Shale with 850-plus The rest of the DUCs were primarily in the Niobrara formation (620 wells), with another 270 in various other onshore regions Rystad (2016) have estimated the completion cost per barrel for the major shale plays to determine the value of DUC s in the major shale plays. Their data indicates the four major counties of North Dakota containing some of the highest value DUC s in the US resource space Completion costs in McKenzie, Mountrail, Dunn and Williams Counties are between $5- $7/bo. These are lower than any of DUC s in the Permian Midland basin and all but two counties in the Eagle Ford and Permian Delaware basins. EOG and Continental both also indicated during quarterly conference calls that DUCs, mostly in the Bakken, Eagle Ford and in Oklahoma, would be a top priority before new drilling. Continental CEO Hamm said We might ramp up completions of DUCs before we would ever consider bringing drilling rigs back. 11 P a g e

12 Bakken Geological Overview This is a summary of the Bakken Petroleum System. A detailed geological discussion of the Bakken is presented in Appendix 1 Bakken-Three Forks sequence is Late Devonian to Early Mississippian age, deposited between million years ago in the Williston basin The sequence reflects an increasing sea level commencing with oxygenated, shallow water clastics and carbonates of the Three Forks formation, and overlain by generally deep water anoxic lithofacies of the Bakken parasequences Source rocks were deposited in the Upper and Lower Bakken interval during increasing sea levels when anoxic conditions prevailed. These units comprise black shale rich in organic matter and with TOC s up to 40%. These are the source rocks of Bakken generated oils Middle Bakken reservoirs were deposited in shoaling marine conditions and are lithologically composed of sandstones, dolostones, siltstones and limestones. Porosities and associated reservoir storage, can be high, up to 8% in some fields. Reservoirs have been enhanced by both vertical and horizontal natural fracturing and post depositional diagenesis. The Middle Bakken is up to 50 thick in places The Three Forks conformably underlies the Bakken in the central portion of the basin. It has been described by N Dakota geologists as a mineralogical garbage can. The formation consists of a thin bedded sequence of greenish and reddish brown shales, light brown to yellow grey dolostones, grey to brown siltstones, and quartzose sandstones with minor amounts of anhydrite. It s mineralogical instability and thin bed nature make it a difficult rock to analyze. The Three Forks Formation reaches a maximum thickness of 250 ft o o Local accumulations of coarse-grained siltstone to fine-grained quartz sandstone occur at the top of the Three Forks. These local accumulations are informally known as the Sanish sand The TFS is not as good a reservoir as the Middle Bakken. Type curve EUR s of the TFS tend to be ~30% lower than the M Bakken Overpressuring (defined by > 0.44 psi/ft) is a characteristic feature of Bakken pools within the oil window. Overpressuring occurs as Bakken source rocks become generative and expel hydrocarbons into Middle Bakken and Three Fork reservoirs. Hydrocarbon charge into these adjacent low permeability reservoirs causes the pressure to be retained in the reservoir (i.e. capillary pressure) until it is released by propagation of vertical and horizontal reservoir fractures Structural inversion on the Nesson Anticlinal Trend is characterized by yo-yo tectonics, a term that refers to multiple periods of uplift and subsidence. The structurally active trend was a low during deposition of Three Forks and a shoaling trend during Bakken deposition. Consequently, Bakken/Three Forks reservoir is well developed in this area. Also post Bakken uplift has produced large scale extensional fractures, which may be a conduit for secondary migration and charge Within the Bakken oil window, oil saturation of Bakken-Three Fork reservoirs is pervasive and with no apparent water contacts. Originally, oil generated within the Bakken Oil Window was thought to stays in the oil window and as such is termed, a continuous oil accumulation. However, nowadays Bakken geologists say this is too simplistic. They point to examples on the structurally active Nesson Anticlinal Trend where faults and fractures appear to have different Oil-Down-To contacts which implies an element of local migration. Outside of the generative oil window, migrated hydrocarbons constitute Bakken resources in the following areas; o Eastern Montana and Northern N Dakota (Divide and Burke Counties)- north of the Brockton-Froid fault zone the Bakken is thermally immature and relies on 12 P a g e

13 o hydrocarbon migration out of the oil window for charge. This area typically has high water saturation and production. Southern Saskatchewan. The Bakken resources in Saskatchewan have migrated out of the Bakken Oil Window by way of the Brockton-Froid fault zone. These Bakken resources have different characteristics from the US Bakken resources, and are not considered in this report Bakken Resource Size- How Big is the Bakken? In 2008, the USGS conducted their first geology-based, resource assessment of the Bakken Petroleum System. In this report they did not include an assessment of the Three Forks, which was discovered later In 2013, the U.S. Geological Survey (USGS) updated their 2008 report with the inclusion of the Three Forks. The Three Forks assessment doubled the size of the Bakken continuous accumulation resource prize (i.e., within the oil window). The USGS estimated mean undiscovered volumes of 7.4 billion barrels of oil, 6.7 trillion cubic feet of natural gas, and 0.53 billion barrels of natural gas liquids in the Bakken and Three Forks Formations o This report highlighted the significant resource potential of the Three Forks with 3.8 billion barrels of undiscovered resources However, since this report the resource size has increased considerably. Since 2013, more productive zones have been encountered and the Three Forks has emerged as a resource size potentially equal to the Bakken. Exploitation of Three Forks Benches 1 and 2 has produced consistent results, while exploration of TF Benches 3 and 4 has produced encouraging, early stage results in places. The impact of the discovery or Three Forks resources resulted in Continental almost doubling their resource size in a two year period. At a recent conference, Continental CEO, Harold Hamm, believes the Bakken could contain 24 billion recoverable boe. However, many believes that Hamm s number is an all in number that includes large Three Forks resources in all 4 Benches. It is our belief that is too early in Three Forks exploitation to say this. Many North Dakota geologists believe the Bakken will ultimately 13 P a g e

14 produce between Billion barrels of oil. For context, some of Brazil s deep water pools are 30 B BO. o At this years Williston Basin conference, North Dakota s chief oil/gas regulator Lynn Helms commented that the Bakken resource is enormous, with only 20% developed to date. This implies a Bakken resource size on the lower end of the range Bakken oil production from North Dakota to date is around 1.6 Billion barrels. There IS still a lot of running room in the Bakken play. With a remaining Bakken recoverable resource range from 5-22 Billion barrels, it looks to us that the Bakken is alive and well- Still the King of pure oil shales The Best Bakken Geological Areas Where are the best Bakken areas? From a non-technical perspective we can see what parts of the Bakken work best by following the money. Drilling activity today has been concentrated in principally four Counties in North Dakota; McKenzie, Williams, Mountrail, and Dunn o McKenzie County has had some very high rate well results in the past two years. Eastern McKenzie Co, in particular, has had some impressive drilling results. The Three Forks is proving to be consistent, with economic production rates established in Three Forks Benches 1 and 2 and with potential indicated in TF Benches 3 and 4. Good drilling results have also been reported in southern Williams County o Mountrail County could contain some of the best acreage in the Williston Basin. Alger, Ross, Sanish and Parshall fields are all in this county and have thick Bakken reservoirs and high production rates These four countries are also contain the most prolific Bakken rocks in the basin and are categorized by three geological areas with similar attributes; The Eastern Oil Window (Parshall, Ft Berthold), The Nesson Anticlinal Trend and the Central Basin Eastern Oil Window- Mountrail and Dunn Counties The area covers Stark, E Dunn, E Mountrail Co., North Dakota Public companies active in the Eastern Oil Window include; Arsenal, ConocoPhillips, Continental, EOG, Fidelity E&P, Hess, Hunt, Jordan Exploration, Marathon, Murex, Oasis, Oxy, Petro-Hunt, QEP, Sinclair, Statoil, Whiting, Windsor, WPX Energy, XTO Of the operators in this area, our coverage includes; o Whiting Petroleum- ~83k net acres in this area in Mountrail o Oasis Petroleum- ~100k net acres in Mountrail o WPX Energy- ~40k (of 86k total Bakken) net acres largely concentrated in the Ft Berthold area o Continental Resources- small acreage position, uncertain size. Geological characteristics of the area include; o Excellent reservoirs- Bakken and Sanish have pervasive dolomitic reservoir consisting of thick higher porosity reservoirs Three Forks is a well-developed reservoir and productive in parts of this area o Overpressure and high thermal maturity o Natural fracturing from oil generation o Thick, high quality source rocks deposited in basins depocentre 14 P a g e

15 The area was the original Bakken core area. The cornerstone field is the Parshall field that was discovered by EOG in Geological attributes of the field include; Thick Bakken reservoirs and high production rates M Bakken in the Parshall Field is significantly overpressured (~6300 psi) and supported by ~1500 oil column Basement faulting was episodically active until the Jurassic which facilitated fracturing of Bakken rock in the Eastern Oil Window (see Appendix 1. Production Analogue- Parshall) The Middle Bakken Formation at Parshall lacks the sandy dolomite member found in most parts of the play but more than compensates with greater natural fracturing, permeability, and pressure than other areas. Three Forks is wet in field area Unlike the Parshall field, the Three Forks has significant resource potential at the Ft Berthold field. Enerplus report that they have been exploiting Three Forks Bench 1 and starting to test the potential of Three Forks Benches 2 and 3. Enerplus states the entire Ft Berthold acreage is prospective for Bakken and Three Forks B1. They have an inventory of 236 future drilling locations o Enerplus consider Three Forks B2 and 3 to be exploratory upside at this point in time. The believe that TF B2 has potential in the NW part of the field Some of the best Bakken wells in 2016 are in the Ft Berthold field. Enerplus has some of the best acreage in this field with high production rates in the crestral part of the structure Enerplus has reported on new completions and improving EURs in Ft Berthold. The longer lateral and high intensity completions have resulted in substantial uplift to their type curve EUR s. The type curve EUR s have improved from the early stage completions in 2012 that had EUR s of around 700 MBO to current high intensity completions with EUR s of 1.2 MMBO o The new completions are a game changer for Enerplus, who now report some of the lowest breakeven costs in the US resource space. They report a breakeven cost of $45/bbl Other operating companies in the Eastern Oil Window are also achieving significant type curve improvements 15 P a g e

16 o Oasis is reporting type curve upgrades of M Bakken to EUR of 1.55 MM Boe and Three Forks EUR of 1.2 MM Boe o Whiting s super completions utilizing >10 MM lbs of sand, are tracking above their 1.5 MM Boe EUR type curve. This is an improvement from their 2015 type curve EUR of 900 MM Boe The evolution of the type curve in the Eastern Oil window type curves from Parshall had IP1 of ~500 boe/d and EUR of 750M BO. However, recent completions have become far more efficient. In 2016, public companies operating in this area have a P50 type EUR of 900 M BO, with a range from MBoe. We expect that the P50 type curve EUR of 900 MM Boe will be economic at around $40 oil Nesson Structural Trend This was the structural trend is a 20 mile wide by 80 miles long structural trend and covers parts of NE Billings, W Dunn, E McKenzie, W Mountrail, and E Williams Co., North Dakota The Nesson Structural Trend is oriented N-S and is situated along the axis of the basin. It is a low, broad regional structure with around 100 of closure. It was formed by the reactivation of basement faults along a Precambrian suture (Anna et.al., 2013) Active Companies in Nesson Trend include; Burlington, Continental, Denbury, EOG, Hess, Marathon, Newfield, Slawson Exploration, Statoil Oil, Whiting, XTO Of the operators in this area, our coverage includes; o Whiting Petroleum- 40k net acres in Dunn Co as well as an estimated ~50k in eastern Williams and McKenzie o Newfield Exploration-40,000 net acres in in McKenzie County o Continental Resources- of the ~860,000 net acres in the entire play we estimate that ~25% or 220k net acres are situated on the Nesson Trend o WPX- have ~45k net acres on Nesson Trend in Eastern McKenzie and Dunn Co The USGS (2013) determined that there was almost 1.3 billion barrels of undiscovered resources in this area. However, recent completions in TFS Benches 3 and 4 suggest this could be conservative 16 P a g e

17 Key productivity drivers in this area include; o Excellent reservoirs- Bakken and Sanish; thickness and porosity are anomalously high in this area. Three Forks has up to 4 productive benches. In this area the Three Forks may hold as much resources as the Middle Bakken o Regional fracturing caused by inversion on the Nesson fault systems o Overpressure and high thermal maturity- oil generative microfracturing o Thick, high quality source rocks deposited in basins depocentre. Diagenetic dissolution and porosity enhancement of thick Middle Bakken reservoir. Addition hydrocarbon storage is provided by the presence of both Pronghorn (L Bakken sandstone) and the Three Fork reservoirs developed in this area Antelope Field (Three Forks) is situated in the central part of the Nesson anticline and was discovered in Production characteristics of the field include a very high reservoir pressure, high productivity wells, and absence of formation water. It has yielded some very high rate wells Colter field in Dunn Co., is situated on the southern end of the Nesson trend. It is productive from Middle Bakken and several Three Forks Benches. In this field, tectonics have created large fractures that allow communication between the TF Benches and Middle Bakken. A recent well tested TFS Bench 3 at 1750 bo/d and high pressure (3200 psi) Perhaps some of the best well results on the Nesson Trend are in the Charleston area, on the central portion of the anticline. One of the best wells drilled was the 2006 Hunt USA 2D-33-1H, unstimulated, short lateral that produced over 1.6 MM BO and may be one of the best wells in the entire Bakken/Three Forks play. This short lateral was unstimulated, suggesting it intersected an extensive natural fracture system. Encore (i.e. formerly DNR) offset this prolific 2D-33-1H well with short laterals of its own, with EUR exceeding 1 MMBoe. The Bakken has been extensively fractured in certain crestal locations but fracture intensity is not uniform In addition, high rate wells have recently been drilled in the Blues Butte field in McKenzie Co and also the Lost Bridges field in Dunn Co. In the former, well have been completed this year at rates of between 3000 boe/d to 4200 boe/d in both the M Bakken and Three Forks Conoco has a premier acreage position on the Nesson Trend. In 2015, indicated their Nesson acreage has the highest value in the play with $20/ boe full-cycle F&D costs and acreage values of as much as $35,000/acre. Conoco are completing wells in the Middle Bakken and Three Forks Benches 1 and are down spacing to 80 acres 17 P a g e

18 Companies operating on the Nesson have also reported large increases in EUR in the past 12 months. Average TC EURs for operating companies average ~ 900 M Boe. Other notable type curve upgrades include; o Oasis type curve upgrades of M Bakken EUR of 1.55 MM Boe includes parts of the Nesson domain o Newfield has increased M Bakken TC EUR increase from 700 MM Boe to their current 950 MM Boe Central Basin, McKenzie and Williams Co, N Dakota The Central basin area primarily covers the counties of McKenzie and Williams in North Dakota Active Companies in the Central Basin include; Abraxas, Baytex, Burlington, Continental, Denbury, Earthstone, Emerald, Enerplus, EOG, Halcon, Hess, HRC Operating, Marathon, Newfield, Oasis, Oak Valley, Petro-Hunt, QEP, Slawson Exploration, SM Energy, Statoil Oil, Triangle, US Energy, Whiting, WPX Energy, XTO, Voyager Of the operators in this area, our coverage includes; o Triangle Petroleum- a pure Bakken play with acreage largely in McKenzie and Williams and resource inventory of 573 gross operated locations o Whiting Petroleum- 161k net acres in McKenzie Co and 74k net acres in Williams Co Abraxas Petroleum- small acreage position of 3.9k net acres in McKenzie Co prospective for Bakken and Three Forks B2 resources 18 P a g e

19 o Earthstone Energy- small acreage position of 5.9k net acres predominantly in McKenzie o SM Energy- ~44k acres in the Bears Den- Raven areas in McKenzie o Oasis- ~300k acres in Western Williams and McKenzie Co The USGS (2013) determined that there was almost 1.1 billion barrels of undiscovered resources in this area. However, recent completions in TFS suggest this may be conservative o o Statoil s recent eight wells at Banks field in McKenzie Co have been the best in the Bakken over the last year. Four wells targeted the Middle Bakken, and four well targeted the Three Forks. All the wells were drilled with 10,000-ft laterals and tested at an average IP rate of ~5,400 boe/d (74% oil) Samson operating in the North Stockyard field in Williams Co has successfully exploited TFS Benches 1-3 The types curves in the Central basin have evolved from initial EUR recoveries of 300 MBoe in 2010 to average 2016 TC EUR of 700 M BO The Worst of the Bakken- Where is the Money is Not Flowing Counties E. Montana and Divide, Burke and Stark Counties in ND have the lowest activity of the Williston Bakken Counties. Data provided by PLS indicates there are no rigs active in Montana now, and there is only one rig active in Divide and Burke Counties in North Dakota. These counties comprise the lowest grade of Bakken rocks. They have much lower productivity, higher water cut and higher supply costs then the three high tier Bakken areas. For instance, wells in Divide Co produce 3-4 barrels of water for every barrel of oil. Operating costs are high. 19 P a g e

20 The area covers Divide Co., North Dakota and Sheridan and Daniels Co., Montana. It is the least developed of the Bakken play area. o The Bakken becomes shallower in Divide county line, where it is less than 9000 deep. The northern Bakken area is characterized by lower maturity and lower kerogen conversion. The lower thermal maturity results in lower formation pressure (i.e. normal pressure gradient of 0.43 psi/ft) and also high water saturations (i.e. Sw= 70%) o In addition, the Brockton-Froid fault zone, allows generated oil and gas to migrate out of the Bakken Petroleum System into conventional (i.e. migrated) Bakken reservoirs in Canada o Expect variability in results with higher water cuts, low thermal maturity and corresponding low overpressure o The USGS refers to this area as the NW Williston AU and they have only assigned 207 MMBO yet-to-find resources in this area, which suggest less attractive attributes of the Bakken Petroleum system in the North Williston From public data provide by PLS, the breakeven cost of this area is ~$65/bbl Active Companies in Divide County; American Eagle Energy, Armstrong Operating, Baytex, Citation Oil, Condor Petroleum, Continental Resources, Crescent Point Energy, Enduro Operating, Hunt Oil, Kaiser-Francis Oil, Mountain Divide, Murex Petroleum, Newfield, North Plains Energy, Petro-Hunt, Samson Resources, Sequel Energy, SM Energy Operating companies in area on our coverage; o Newfield Exploration- 52k net acres in Montana and western McKenzie areas o Continental Resources- 245k in Montana o SM Energy acreage in Divide Co. has one of the largest positions, with ~135,000 acres at Gooseneck in Central Divide County. SM Energy do not state what their TC EUR is. However, Baytex, who previously held the acreage, were carrying EUR of 420 M BO prior to the sale, in mid In 2014, American Eagle, which has offsetting acreage to SM Energy indicate TC EUR s of 350 M BO and 450 M BO for the Bakken and Three Forks respectively. SM, however, is completing wells with 10,000 laterals and plug-and-perf completions which will increase recoveries from the 2014 vintage completions. We expect an EUR of <500 M BO oil may be reasonable 20 P a g e

21 Montana The area covers all of Eastern Montana including Richland, Roosevelt and Sheridan Counties in E Montana The Middle Bakken thins to 20- to 30-feet thick along the border of Montana and North Dakota from a maximum thickness of ~85 feet in the center of the basin. It is also less thermally mature and becoming normally pressured In 2016, Oasis indicates that the EUR of between M BO is applicable for their Montana acreage. However, the lower end of the range is expected farther west into Montana. A reasonable average EUR is expected to be ~500 M BO 21 P a g e

22 Part 2- Summary of Several Bakken Focused, Public Companies Disclaimer: I am not an investment advisor and this is not a recommendation to buy or sell a security. I am a geologist, not a CFA. The information and data presented was obtained from company documents and/or public domain sources believed to be reliable, but have not been independently verified. Therefore, the author cannot guarantee their accuracy. Please do your own research and contact a qualified investment advisor. I am not responsible for investment decisions you make. 22 P a g e

23 Continental Resources (CLR)- NYSE Shares outstanding; MM Public Float; MM Short Interest; 0.25 M representing 23% of float Market capitalization; $ B Enterprise value; $ 25 B Net Debt; $ 6.8 B Net debt/ye 2015 Proved Reserves; 5.87 Net debt; EBITDAX; 3.88 Enterprise Value/EBITDA; week range; $ Sept price; $49.50 Current production (Q3); 207,000 boe/d Summary; Continental Resources is a large cap company with considerable torque to higher oil prices. The have large growth resources assets with positive drilling economics in two of the premier resource plays in the US; the Bakken and the STACK/SCOOP plays in the Anadarko basin, Oklahoma. They have a large inventory of ~240 DUC s in these plays that provide CLR with optionality to drive upside to consensus estimates for 2016 and P a g e

24 CLR s original 2016 CAPEX budget was $920 MM and, at their Q3 call, they advised this would be increased to $1.1 B and provide free cash flow at YE16. In 2016, CLR has been drilling for acreage preservation and contractual obligation. They have high acreage retention issues in the SCOOP area with 100,000 net acres expiring in the next two year (as of YE15). CLR s Q2/Q3 could have been described as lackluster. CLR s Q production 207,800 Boe/d, 5% lower than Q2. However, we attribute this to prudent and cautious capital deployment. At YE15, CLR advised activity would be driven by oil price. Under $45 oil, CLR s activity would conserve cash and strengthen the balance sheet. Between $45-60, CLR would complete the large inventory of DUC s, particularly those in the Bakken and above $60 oil, the company would begin to add drilling rigs. This year, CLR has sold ~ $900 MM in noncore asset sales. CLR has made considerable improvements in horizontal well completion, increasing type curve EUR s across all resource plays from 711 M Boe in 2014 to 1.2 MM Boe in CLR has also shown strong cost control in 2016 by reducing production costs and G&A. Consequently, EUR/operated well is up 70% and capital efficiency increased by 133% over a two year period of declining oil price. Most of CLR s horizontal wells are now high intensity completions comprising 10,000 laterals with frac stages. CLR is also experimenting with enhanced slickwater and hybrid completions that continue to improve well performance. In the Bakken, CLR has recently drilled three 15,000-ft-plus laterals with a single drill bit and motor. Continental is one of the largest operators in the Bakken play. They were an early entrant in the Elm Coulee Field in Montana in the early 2000 s and since then, the company has drilled over 4,000 Bakken wells. Continental started as a Bakken company and still is a dominant player and technology leader in the play. CLR now have ~ 860,000 net acres (down from over ~1 MM net acres at YE15 due to non-core asset sales). Approximately 30% of the acreage is located in the best parts of the Bakken, in eastern McKenzie, Mountrail and Dunn Counties. CLR will spend $320 MM in the Williston basin this year. They report Bakken Type curve EUR of 900 MBoe that provides 40% IRR at $50 oil and is economic at $38 oil. We expect that new Bakken wells will continue to outperform this type curve. We estimate that CLR has ~2500 risked Bakken resource locations in inventory. At Q3 call, CLR indicated they have commenced conversion of Bakken DUCs. The company has currently has two stimulation crews working and plans to have a total of four crews operating by YE16. In July this year, they had ~190 DUC s in the Bakken and by YE16 they expect to have 175 DUC s in inventory. The company carries a Type Curve EUR of 850 MBoe for their DUC inventory. However, with recent improvements in completion design, this may be conservative. In the past few years, CLR s emerging growth area is in the Anadarko basin, in the STACK and SCOOP play areas with ~ 970,000 net acres. They have accumulated an impressive acreage position of 326,000 net acres in the STACK play. The company plans to spend $ 142 MM in the STACK this year. CLR have been drilling in the overpressured window of STACK with promising results. In particular, the Q2 wells at Madeline 1 9 4XH and the Frankie Jo XH had IP s of 3,500 and 2,600 boe/d respectively. The company has 11 rigs running currently and have derisked several areas and are even testing down spacing options in these areas. CLR has a 24 P a g e

25 STACK Type Curve EUR of 1.7 MM Boe that generates an IRR of 100% at $50 oil. The company have identified 1,200 resource locations in the overpressured part of the play. This is a very high value asset and one that CLR management plan to make the cornerstone of their new resource base. In the SCOOP area, CLR plans to spend $240 MM by drilling 24 gross/16 net operated wells this year. CLR has 445,000 net acres in the Scoop Woodford condensate play, which has driven a sharp 30+% increase in productivity with recent wells. We caution investors to the early stage variability of the play, which we believe may be high. CLR has recently increased type curve EUR by 15% to 2,000 MBoe that has an IRR of 50% at $3 gas. Debt is a slight concern but not an impediment to growth in a rising price environment. CLR s long term debt of $6.8 B includes $2.75 billion revolver, with $870 MM drawn and ability to upsize to $4.0 B. The revolver matures on May 16, As of July 31, 2016, CLR had available liquidity of $1.93 B and nearest debt maturity in Nov 2018 with $500 MM due. CLR s target is to use a combination of cash flow and non-core asset sales to bring down debt to $6 B. Expiring acreage is also minor concern in a volatile price environment. The combined net acreage expiring in the next three years represents 60% of the total net undeveloped acreage at December 31, CLR has a deep inventory of high quality infill inventory of between locations in the Bakken, STACK and SCOOP plays. We estimate there may be 3,700 risked locations (SCOOP and STACK areas are heavily risked). At YE15, CLR proved reserves were 1,226 MMBoe and valued at $ B. Proved value less debt is ~$3/sh, and we estimate fully developed risked resources valued ~ $72/share(at YE15 pricing). At CLR s current trading price of $49/sh investors are paying for Proved Reserves and debt plus about 60% of the risked resource inventory locations. CLR has torque to oil prices, with $1/bbl increase in oil price increasing CLR s PV by ~$280 MM EXPECTED CORPORATE PERFORMANCE: High productivity assets in Tier 1 areas of the Bakken and STACK plays. High level operational execution with continually improving well productivity and type curve EUR s. CLR average M Bakken type curve EUR of acreage 900 MM Boe type curve is economic at $38 oil price. Investors have upside in continued completion improvements and can expect to see increases to type curve EURs, possibly 1200 MM Boe EUR type curves that other operators are reporting. CLR have commenced conversion of DUC s to producers in the Bakken, where they expect to have 4 completion crews active by year-end. The company says the DUC conversion has 100% ROR for incremental completion cost at $45 oil. This DUC conversion is expected to provide superior financial returns at year-end. In the STACK play, CLR is also situated the core of a premier resource play that has strong D&C economics at sub $40 oil. They have a deep inventory of economic resource inventory locations these two premier resource plays. Driven by strong well performance, the company has exceeded quarterly production guidance in We can expect the trend to continue in Q4. At $60 oil price expect CLR to increase drilling activity and with a deep resource inventory, with strong economics at current oil prices, we expect the corporate results will OUTPERFORM our Bakken basket of companies. 25 P a g e

26 Earthstone Energy- NYSE- ESTE Shares; 22.3 MM Mkt. Cap $191 MM, Total Debt; $ 10 MM, EBITDA; -$132.4 MM EV:EBITDA; EPS; -$9.45 Cash Flow (operations); -$ MM Free Cash Flow; -$ 37.3 MM 52 week range; $ $21.04 Early Sept price; $9.91 Q2 production; 3,759 boe/d Proved Reserves (YE 2015); MMBoe Summary Texas based public company with market capital of $229 MM. Since 2014, ESTE has evolved from a startup, non-operated Bakken pure play company to a Permian/Eagle Ford growth company. ESTE began as a Bakken startup in 2014 with ~600 boe/d that grew to P a g e

27 boe/d in Q2 2016, from primarily the Bakken and Eagle Ford. However, in early Q4, ESTE announced they acquired and 2,320 Boepd (63% oil) on 20,900 net acres in the Midland basin acreage from Bold Energy. With this transaction ESTE is now producing 7393 boe/d. ESTE indicate they now have ~1000 gross resource locations in these core plays. We believe this could be a transformational acquisition for the company. The Bold Energy deal provided ESTE with 20,900 net acres in Reagan, Upton and Midland Counties, TX with net production of 2,320 Boepd (63% oil). ESTE now have over 500 gross operated high potential 2P locations to their Midland basin resource inventory. These locations have been largely de-risked by 18 gross horizontal producing wells drilled by Bold. Type curve EUR s range from 700-1,000 MBoe (56-71% oil). ESTE expect to grow Permian basin production to between ,500 boe/d by YE ESTE 2016 CAPEX program has been focused on the Eagle Ford and the Bakken. ESTE s CAPEX program was $42 MM, with $31 MM allocated to the Eagle Ford and $7MM to the Bakken. ESTE have 18,600 net operated acres in the Eagle Ford in Gonzales, Fayette and Karnes Co., TX. This includes completing 12 gross DUC wells and to drill and complete 5 gross wells. ESTE have identified an Eagle Ford resource inventory of ~220 gross location. We have estimated that the company may have ~75 net risked locations and possible resource prize of ~30 MM Boe. We also like ESTE s Eagle Ford capital program for providing validation of upside potential without high capital concentration risks. In the Bakken, ESTE have 5,900 net core acres predominantly in McKenzie and Dunn Co. This acreage is prospective for both the Bakken and Three Forks formations. The majority of ESTE s acreage is in the Banks field, McKenzie Co. The Banks field is operated by Statoil who are completing wells with high intensity fracs. ESTE report a type curve EUR of 600 M Boe. ESTE s 2016 Bakken CAPEX was $7 MM of which 83% was/is deployed to completing wells in their DUC inventory. ESTE report these completions an IRR of > 80% at current oil prices. This completion activity is expected to provide upside to the operational execution and improve the YE financial results. However, ESTE have only ~140 gross/ 4 net locations in resource inventory. Although these locations maybe economic, the small net inventory is immaterial for production growth, which is clearly the company s strategy. ESTE s small 4% WI in the Bakken play is operationally inefficient and offers no upside. We believe ESTE could potentially sell the asset to its partners. If ESTE s asset could be sold, the company may be expected to get more than $25 MM or so (PDP PV). This provides the company optionality to reduce debt, and redeploy capital to more impactful projects, should well results prove to be as expected. In June, the company completed an offering of 4.5 MM with proceeds of $44.7 MM. ESTE used proceeds to reduce indebtedness under its revolving credit facility from $47.8 MM to 10MM. ESTE now has net debt of $10 MM. In August 2016, ESTE had $83 MM in cash and liquidity. We value Proved value less debt to be ~$6.00/sh. We estimate that ESTE have ~200 risked, net resource locations across the two major resource plays in the Eagle Ford and Permian. We estimate total risked resource upside plus Proved value and debt is around $45/sh. The largest component of upside is ~$25/sh for the new resources in the Permian 27 P a g e

28 inventory. ESTE s current share price of ~$13 implies investors are paying for the Proved Reserves and Eagle Ford inventory. From this perspective investors would not be paying for any Permian resource in the current share price. We believe this represents an attractive entry point to the stock exit rate over 6000 boepd, largely provided by EF. ESTE is hedged for the second half of 2016 with ~2,010 Boepd at average oil and gas prices of $49.35/Bbl and $2.604/MMBtu, respectively. Catalysts include ESTE s first operated Permian basin well Tubb A 1HA located in the Howard County which is now on flow back, and a number of Eagle Ford completions by YE. ESTE is a thinly traded stock. As a result, investors may find it costly to build or reduce a position in the stock over a short time frame EXPECTED CORPORATE PERFORMANCE: ESTE is an early stage growth stock focused on the economic resource plays in the US; the Eagle Ford, Bakken and Permian. They have a strong management that has a history of value creation in the oil and gas resource sector. The company is developing a potentially significant resource base in the Eagle Ford and, most recently, the Permian. We view the company as a transition story into a Permian growth company but with solid supporting assets in the Eagle Ford and Bakken. By YE2017, ESTE believe they can increase Permian basin production to between ,500 boe/d by adding 1 and 2 rigs respectively. We view ESTE s Bakken acreage in the Banks Field in McKenzie Co as a solid asset, but with only a 4% WI, lacks materiality. However, we believe the Bakken acreage provide the company with optionality- the asset will generate reasonable financial returns or with a timely asset sale, ESTE could redeploy capital to a derisked, potentially material assets in the Permian. Large number of catalysts in Q4 including the conversion of Eagle Ford DUC s, updated well performance from recent completions in the Boggs and Flatonia fields in Eagle Ford and the companies play opening Tubb A 1HA well in the Permian. Expect the results to OUTPERFORM our basket of Bakken operating companies. 28 P a g e

29 Newfield Exploration- NYSE- NFX Shares; MM Mkt. Cap $ 8.5 B Net Debt; $ 2.2 B 2016 CAPEX; $ MM EBITDA; -$ 2.49 B 2015 Cash Flow (operations); $ 1.2 B Current production; 83,700 boe/d Proved reserves; 509 MM Boe PV 10; $2.9 B 52 week range; $ /sh Current price; $44/sh Summary Although formerly international E&P, NFX is on a transformational path of to a pure Anadarko basin pure play. Since basin entry in 2012, NFX has accumulated an attractive acreage position of 315,000 net acreage mainly in the high productivity SCOOP and STACK areas. NFX has made impressive improvements to their STACK type curves which now has a highly economic EUR of 1.1 MM Boe. These assets contribute 53% of total proved reserves 29 P a g e

30 of the company. In 3Q16, NFX s Anadarko Basin average net production reached 93,400 Boe/d. NFX has increased upward revision of production guidance 3 times since YE Almost 90% of NFX s 2016 CAPEX program is being deployed to the Anadarko basin. Only 4% is allocated to the Williston basin. However, NFX has 116,000 net acres expiring in the Anadarko basin over the next 3 years. Investors should be aware that should oil prices remain low, NFX could face unattractive drilling obligations, reserve impairments and erosion of upside potential. Over the past two years, NFX has faced significant reserve impairments, the most recent in Q2, and with oil prices approaching $50/bbl, same as at YE, we don t believe this will be a significant threat to company s wellbeing. NFX produces ~18,000 boe/d from the Williston basin. NFX s Williston acreage is situated in two areas; 40,000 net acres in the highly valued Nesson-east trend in McKenzie County core area and also 52,000 net acres in lower value Montana and western McKenzie areas. The former Nesson Trend acreage is in the best areas of the Bakken. NFX type curve EUR for this area is a healthy 950 M Boe, which we expect would be economic at ~$40 oil. However, we view 40,000 acres in McKenzie County as too small to facilitate transformative growth. However, the Bakken acreage provides optionality. With almost all CAPEX directed towards the lease preservation in the Anadarko basin, the Bakken acreage provides a potentially powerful trading chip from which the company could accelerate growth in the Anadarko basin, should that be justifiable. In addition, the non-core assets in China, and the US including in the Unita basin and Arkoma basin could be opportunistically sold to assist deleveraging. NFX Debt is only a slightly concerning. Net debt edged up to US$2.3 billion, largely due to the Q2 STACK activity. However, debt levels have remained stable over last few years and the company has been paying down debt with opportunistic asset sales and equity raises. In Q4, Moody's upgraded NFX to a Ba2 rate and with a stable outlook. No fixed term debt maturities for 6 years ($750 MM in 2022) and substantial liquidity of $2 B. Another factor that investors should be aware of is the likelihood of further reserve impairments in 2016 as a result of continued low oil prices. In Q2, NFX conducted a ceiling test and advised that impairments in the H could exceed $100 MM based on the forward strip pricing. However, we believe that the reserve additions from the aggressive drilling program in the Anadarko basin will more than offset this. AT YE 15, NFX booked 509 MM Boe PROVED reserves with PV 10 of $2.9 B or $14.6/sh. Proved reserves less net debt is ~$3.50/sh. The current share price of ~38/sh implies that investors are paying proved reserves plus debt, all Bakken and SCOOP resource locations, and 1000 STACK resource locations. We feel this is an expensive stock. NFX share price has performed well this year and is largely attributed to strong well performance in the SCOOP and STACK play areas. Rising gas prices also added to NFX share buoyancy. NFX is well hedged (long $73/bbl for 23,000 boe/d Q EXPECTED CORPORATE PERFORMANCE: Newfield is a company in transition. Their primary focus is on the STACK play in the Anadarko basin. Over half of the company s reserves are on 315,000 net acres in the Anadarko basin. We expect results from the $ CAPEX to outperform peers. In the Bakken, we see high value in the company s ~40,000 acres on 30 P a g e

31 the Nesson Anticline. The Bakken 950 MM Boe type curve EUR provides attractive returns that will outperform peers. This acreage gives the company great optionality; they can expect to continue to see strong financial returns from the Bakken, or they could potentially sell the asset. NFX Bakken is ~18,000 boe/d and with ~40,000 net acres on the Nesson anticline that on a conservative flowing boe basis could potentially generate more than $ 800 MM that could be redeployed elsewhere. Similarly, we view the Unita and China assets as potential divestment candidates, but significantly lower value than the Bakken. The share price has performed well this year. It has increased from around $25/share in Jan to a year to date high of $ in Aug. We except NFX to OUTPERFORM relative to our Bakken basket. 31 P a g e

32 Oasis Petroleum (OAS)- NYSE Shares outstanding; 180 MM Public Float; MM Market capitalization; $ 1.61 B Enterprise value; $ 3.77 B Net Debt; $ 2.13 B Enterprise Value/EBITDA; 7.91 Net Debt: EBITDA; week range; $ Sept price; $ 8.94 Q2 production; 49,500 bo/d Summary; Oasis (OAS) is a mid-cap company that is a pure play in the Bakken. OAS is producing ~49,500 boe/d from an acreage base of 485,000 net acres in the Williston Basin. The acreage is situated concentrated positions prospective for the Bakken and Three Forks. We consider much of OAS Core and Extended Core acreage is high value, and has low supply cost of sub $55/bo. OAS recently completed a bolt on acquisition of ~55k net acres, expected Q4 production of 12,400 Boe/d and ~226 gross operated resource locations in McKenzie Co. from SM Energy (SM) for ~$785 MM. OAS indicate the properties had 50.2 MM Boe of proved reserves, 63% 32 P a g e

33 of which are considered proved developed producing. The company had funded the acquisition through a $ 575 MM equity raise. OAS Core acreage is situated in eastern McKenzie Co and western Mountrail Counties. These areas included the prolific Eastern Oil Window and Western Nesson trends. In the former play area, operators are reporting type curve EUR s ranging from between M Boe with average of 900 M Boe. OAS high intensity completion Bakken core type curve has an impressive EUR of 1.55 M Boe and robust economics at sub $35 oil. OAS have also reported increases in their Three Forks EUR s to 1,200 M Boe. OAS has 3 prolific fields in Core acreage; Alger with 17,000 net acres, Wild Basin with 18,000 net acres, and Indian Hills with 39,000 net acres. Both Bakken and Three Forks have high potential in these fields. OAS have identified ~400 net locations of resource inventory in their Core Area. OAS have also defined an Extended Core area which includes the S Cottonwood, Red Bank and Painted Woods areas in Western McKenzie and Burke Counties. The Bakken is the main resource in this area. In places of OAS Extended Core, some operators are testing the TFS but reservoir quality and oil saturation is variable. OAS high intensity Bakken type curve from this area has EUR of 750 M Boe and is economic at ~$50 oil. Other operators in the Central Basin (i.e. western McKenzie Co.) have Bakken type curve EUR s of M Boe. OAS have identified ~525 net resource locations in their Extended Core area. OAS have also identified ~1200 net locations in 177,000 net acres other areas of the Bakken play including Montana and Burke Co, N Dakota. These will have high variability and will require ~$65+ oil to have any value. As such, we attribute no value to this inventory. OAS has additional financial upside in their operations with 83 gross wells in DUC inventory. These provide the company with optionality to enhance financial performance. This is a high value inventory in Wild Basin where 45% of the inventory resides. 35 % of the DUC inventory is in the Indian Hill/Alger areas and have moderate value. Around ~20% of the inventory is in the Red Bank area and Montana. These represent lower value inventory. OAS Q2 results were good with production coming in higher than expected and cost lower than expected. However, Q216 EV to adjusted EBITDA is 11.1, the highest in recent years. This Q2 metric is considerably higher than its historical average EV:EBITDA multiple of ~7.5x. Net debt of $2.1 B has been stable for past year. OAS conducted a financing in early 2016 which paid down debt by $200 MM. OAS s first senior note maturity is not until early 2019 and is $400.0 MM. However, within the next 4 years from the 2019 maturity, ~$2 B comes due. The interest cost of these notes is ~ $800 MM over the next 6 years. As of June 30, 2016, OAS had an unused borrowing base committed capacity of $1,100.8 MM. However, with expected cash flow of ~$450 MM this year, OAS can only drill ~35 net wells this year to remain FC neutral. With oil price volatility expected to persist into 2017, deleveraging remains a necessity. A potential midstream unit sale of Oasis Midstream Services (OMS) subsidiary provides optionality for Oasis deleveraging. Based on an expected EBITDA of ~$75 MM in 2016, the OMS sale could possibly attract a price of between $ MM, which would improve their financial outlook. However, OAS has been contemplating this sale for a few years and given 33 P a g e

34 current oil price environment, a sale may be difficult and not bring in as much as OAS would like. Well hedged with 80% of 2016 hedged at $49. Only ~40% hedged in 2017 and in the event the oil price weakness persists balancing the budget may become more challenging. OAS Proved Reserves in June 2016 were 221 MM Boe had a PV 10 of $ 1,806 MM, or ~$10/share and Proved less net debt of $0.50/sh. We estimate OAS Resource inventory consists of ~350 net risked core locations and ~400 net risked extended core location provide a developed value of ~33/sh. We have a total risked valuation of ~$35/sh. The current share price of ~9/share implies Proved Reserves, Net Debt and ~30% of OAS s Core Risked Resource locations are imbedded in the current price. EXPECTED CORPORATE PERFORMANCE: Great acreage in the best parts of the Bakken. Large count of Bakken/Three Forks high value resource inventory. OAS has become a technology leader and now carries the highest type curve EUR of 1.55 MM Boe of the operators we have studied. With a D&C 2016 CAPEX program that is expected to complete 28.6 net wells in 2016, investors can expect superior well performance. Inventory of DUC s provides the company with able to improve financial results. With a risked upside valuation of $35/sh may represent an attractive entry point with a $9 share price, small free annual cash flow as consequence of debt servicing, limit the pace at which growth can occur. Lots of upside if they can deleverage. In our opinion selling their OMS subsidiary would be a positive step in this direction. However, until that happens, debt over hang will continue to cloud the outlook. Despite this, we expect the company s DUC and 400 net core locations in inventory, the company will outperform our Bakken basket 34 P a g e

35 SM Energy- NYSE- SM Market capitalization; $ 3.42 B Enterprise Value; $ 5.2 B Shares Outstanding; MM Float; MM Shares short; MM Net Debt; $2.18 B EBITDA (YE 15); -$ 264 MM 52 week range; $6.99- $ Early Aug price; $29.58 Current production; 147,500 boe/d Proved reserves; MMBOE Summary SM Energy is a mid-cap with significant acreage positions in premier shale plays including the Bakken, Eagle Ford, Niobrara, and most recently, the Permian. SM Energy have an enterprise value of $4.6 B and production ~147,500 Boe/d (31% oil). They have a 2016 CAPEX of ~$700 MM, down by 46% from CAPEX is allocated to; 30% Bakken, 30% Permian, and 30% Eagle Ford. 35 P a g e

36 2016 operational activity is dominated by converting DUC s to producing wells. This year, SM plan more than 115 net completions which should continue to drive superior financial results. Q2 results contained a large consensus beat including higher-thanexpected production volumes mainly from great Eagle Ford results. SM reported first half 2016 EBITDA of $399.4 MM. SM has ~190,000 net acres, primarily in the core of the condensate window in the Maverick Basin (western Eagle Ford). These are high productivity, wet gas prone acres. SM have >900 economic drilling locations in the Eagle Ford that has become is a growth engine for the company. This is SM s highest value, mature resource asset. SM is a company in transition from Bakken to a Permian resource focus. In Oct, SM announced parallel deals that divest of their best Bakken acreage of ~45,000 net acres in Bears Den area, McKenzie Co and acquired 35,700 net acres in Howard and Martin Co. in the Midland Basin (Permian). SM acquired the Permian basin acreage at an expensive ~$45,000 on a per acre basis or for $1.1 B in cash and $500 MM in stock. However, the acreage is a bolt on to their cornerstone acreage in the play where they now have a footprint of 82,450 net acres. SM sold their Bakken acreage for $ 785 MM to OAS. Clearly, SM s Bakken strategy has not worked out. SM was a late entrant to the Bakken, SM ended up with suboptimal acreage. They are still digging out of their late stage expansion into fringe areas of the Bakken play through the 2014 acquisitions of Baytex acreage in Divide Co from Enerplus. Since this acquisition, SM acquired additional acreage in Divide Co where the company now holds ~120,000 net acres in this low productivity area. Geological characteristics of Divide Co include; very steep initial decline rates, thin pay zone, no overpressuring and high water saturation. Producing wells in Divide Co commonly 3-4 barrels of water for every barrel of oil. SM s continued CAPEX spend in Divide Co is not compelling and will continue to result in poorer financial metrics. SM are only completing wells with a 30-stages and 3 MM lbs of sand and not the high intensity fracs that other operators are employing. We expect that a type curve from this area would be ~450 M Boe and require $65 oil price for attractive drilling and completion economics. SM s best Bakken acreage was previously in the Bears Den- Raven areas, eastern McKenzie Co. This was the best area of the Bakken in SM s acreage. SM have other acreage in the Bakken, in particular in Montana, and also Dunn and Williams Co. While the former area is unlikely to have any value at current prices, we expect the company will try to monetize the Dunn and Williams Co. acreage. We believe it s unlikely that SM would be able to sell the Divide Co acreage for any meaningful price. SM is a recent entrant to the Midland (i.e. Permian) Basin. They are clear shifting primary focus to this play and winding down operations in other areas. By 2017, SM CAPEX will only be allocated to two areas; the Eagle Ford and the Permian basin. SM expects to grow production from around 800 boe/d currently to over 40,000 boe/d in two years. SM believe that they can grow production by 160% in 2017 and 80% in They have identified a potential resource of over 4000 potential locations on their current 83,750 net acres in the Midland Basin. 36 P a g e

37 At YE 15, SM reported ~$ 547 MM or -$ 6.30/sh in PUD impairments and retirement. This was largely offset by reserve additions and performance revisions. At YE15, SM lost 115 MMBO due to reserve revisions as a consequence of the 5 year PUD rule. We might anticipate expect a similar level of PUD reserve revisions this year a result of low 2016 operational activity, particularly in marginal value acreage such as the Rocky Mountain assets where SM have ~387,000 net acres and carry a 43% PUD booking with a PV of $130 MM. This is expected to be offset but reserve growth in the Permian. Liquidity of ~$1 B and no bond maturities until % hedged in Q3-Q (55% oil) and 45% hedged in 2017 Proved value less net debt of $ 2.1 B is - $ 3.57/sh. SM have 900 locations of resource inventory in the Eagle Ford and over 4000 locations in the Permian basin are the reasons to own this stock. We estimate that this risked Eagle Ford inventory could provide over $30/sh upside. We estimate that a heavily risked Permian inventory would carry an upside valuation of over $20/sh. The current share price implies investors are paying for reserves less debt and 30-40% of Eagle Ford resource inventory BOTTOMLINE; Good acreage in Eagle Ford and the Permian resource plays are the growth engines of the company. Transitioning out of low productivity Bakken acreage to focus on production growth from the Permian. In 2016, SM plans to spend ~$210 MM on very marginal Bakken assets. SM s Q2-Q3 well completion results from Divide Co averaged a dismal 385 Boe/d. Our view is that Bakken well results will UNDERPERFORM our Bakken basket. In addition, they recently sold their best parts of the Bakken and remaining acreage has very low value. Consequently, we believe that SM will be unable to sell these assets for any meaningful amount. However, the company s Q2 revenue beat was largely attributed to good Eagle Ford drilling results. The company has 161,000 net acres with over 900 economic resource locations that should provide good financial returns or the option to monetize, should this be justified. What has caught the attention of investors has been the Permian Midland basin. The company has plans to grow production from 8000 boe/d currently to over 40,000 boe/d from the Midland basin in two years. Investors should be cautious about learning curve performance. However, early well results are encouraging. SM share price has performed well this year, improving from under $10/sh in Feb to $41/sh in December. Given the share price appreciation, we view the company as PERFORMING versus our basket. 37 P a g e

38 WPX Energy (WPX)- NYSE Shares outstanding; 334 MM Public Float; 306 MM Short Interest (of float); 14 % Short Shares; MM Market capitalization; $5.4 B Enterprise value; $ 6.6 B Cash; $1.13 B Total Debt; $ 2.73 B Enterprise Value/EBITDA; 14.4 Net Debt: EBITDA; EBITDA; $ 460 MM 52 week range; $ Sept price; $ 11.43/sh Q2 production; 85,200 boe/d Summary; WPX is a mid-cap company that it transforming from a gas producer to an oil weighted producer. Since 2014, WPX have completed ~$5.5 B of asset transactions including selling of ~ 2 Tcfe of gas reserves in the Piceance Basin in Feb In Q2 2016, WPX reported 38 P a g e