Revisiting U.S. Crude Oil Production Economics Crude Oil Going to $60? Sell E&Ps! December 2, 2016

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1 Macro/Thematic Report Revisiting U.S. Crude Oil Production Economics Crude Oil Going to $60? Sell E&Ps! Contents Production Economics 2 Investment Themes 17 Appendix A: E&P Slides 31 Appendix B: Bankruptcies 35 Appendix C: FCF Matrices 37 Disclaimers 50 Investment Highlights The current cash flow breakeven crude price is 59.26/Bbl but service costs are rising OPEC was effective in crippling the balance sheets of U.S. producers - the average Z- score is now.96 A decline to $2.00/MMBtu HH gas prices would offset a roughly $12.00/Bbl increase in crude oil prices for U.S. E&Ps Investors can profit by owning oily E&Ps and hedging their natural gas exposure via ETFs Research Analyst: Nathan Weiss nweiss@uniteconomics.com (617) Executive Summary In late 2014 we examined the cost structures and production economics of U.S. E&Ps in a report entitled Are U.S. Crude Oil Production Costs $20, $55 or $100 per barrel? YES! Most importantly, the report explained how U.S. oil and gas producers were burning cash at $100 crude despite all-in cash costs of $54.57/BOE (production costs + taxes of $17.63/BOE and maintenance CapEx of $36.94/BOE): Average price realizations were only $46.30/BOE as 65.9% of production came in the form of relatively lowprice natural gas and NGLs. We also discussed the balance sheet implications and financing needs of the U.S. E&Ps in light of OPEC s plan to cripple them. Fast forward to 2016 and we find the average Z-score of the thirty-seven companies analyzed for this report is.96, well into likely bankruptcy range. OPEC mission accomplished! The late-2014 report was intended to be a one-off, but we decided several months ago an update was warranted to contrast cost structures and price realizations from cycle peak (mid-2014) to trough (mid-2016), as well as to provides a framework for determining the necessary crude oil prices to incentivize production growth. Due to lower production taxes, fuel expenses and service costs, we calculate cash crude production costs have declined from $102.22/Bbl in Q to $59.26/Bbl in Q This report also urges clients to take a more integrated view of oil and natural gas prices: Few analysts appreciate that a decline in HH gas prices to $2.00/MMBtu would offset a roughly $12.00/Bbl increase in crude oil prices - leaving U.S. E&P price realizations unchanged even as crude oil climbs above $60.00/Bbl. While U.S. E&P share prices will almost certainly move higher if WTI crude climbs above $60.00/Bbl in 2017, the rally will be muted as increased crude oil pricing fails to translate into improved revenue or cash flows for producers due to declining natural gas prices and rising service costs, much the same way higher gold prices failed to translate into improved financial performance for gold miners during the past cycle. Stating the obvious, we expect shares of the more oily producers (DNR, REI, REN, CPE, RSPP, CWEI, FANG and WLL) to meaningfully outperform the gassy producers (ECR, GPOR, COG, RRC, REXX, AR and SWN). This report goes on to provide two new E&P baskets, replacing our Floundering Five bankruptcy candidates (which have seen average share price declines of 70.1% since we introduced them in December, 2014) and our Safe Seven (-1.5%). We also introduce a very interesting UNGassed strategy: Shorting the natural gas exposures embedded in E&P shares via ETFs to create synthetic crude oil pure-plays.

2 Revisiting U.S. Crude Oil Production Economics U.S. E&Ps - Their Production Mix and Price Realizations In late 2014 we examined the cost structures and production economics of U.S. E&Ps in a report entitled Are U.S. Crude Oil Production Costs $20, $55 or $100 per barrel? YES! Most importantly, the report explained how U.S. oil and gas producers were burning cash at $100 crude oil despite all-in cash costs of $54.57 per BOE (production costs + taxes totaling $17.63 per BOE and estimated maintenance CapEx of $36.94 per BOE): Average price realizations were just $46.30/BOE as the majority of production (65.9%) came in the form of relatively low-price natural gas and NGLs. The seemingly-low realizations were best understood by simply multiplying the average percentage of production classified as crude oil by the average WTI crude oil price ($97.37/ Bbl in Q3 2014) and all remaining production by the average Henry Hub gas price ($3.95/MMBtu in Q3 2014), creating a quite simple, but surprisingly accurate proxy for U.S. E&P price realizations. We utilized the same methodology to create updated price realization estimates for the thirty-seven U.S. E&Ps analyzed for this report, with the results displayed on the following page. Based on average second quarter pricing for WTI crude ($45.64/Bbl) and Henry Hub (HH) natural gas ($2.25/MMBtu) - as well as the production mix of each company - our proxy estimated average second quarter realizations were $23.89/BOE, almost exactly inline with the reported average realization of $23.71/BOE, excluding derivative gains and losses. At the company level, our proxy estimated second quarter realizations within $2.00/BOE of reported realizations for 67.6% of the companies analyzed (25 of the 37). Differentials were generally to blame for variances. How Data is Presented in this Report Before we move on to our more recent findings, we will briefly discuss the formatting of the tables contained in this report. The thirty-seven companies displayed on each table are sorted by estimated crude oil production costs (all-in cash costs per barrel, including overhead, interest expense and maintenance CapEx), with the lowest cost producer first. The tables are split into two sections, with oil and gas producers in the upper section and natural gas producers in the lower section. Companies with more than 90% of production classified as natural gas and NGLs are considered natural gas producers. The (current) Permian producers are highlighted in yellow. While these eight companies are not necessarily the lowest cost producers today, recent well results show Permian geology responds incredibly positively to higher frack and proppant intensity while showing minimal negative effects from downspacing programs. Permian producers are also among the most oily in the United States, as we show on page six, and we believe market participants are wrongly-focused on per-acre metrics rather than valuations on a per-well basis - which we discuss later in this report (page 21). Any datapoint shown in red text has been overridden or adjusted by us for various reasons, most often due to one-time costs or charges or an error in a Bloomberg data feed. Finally, the totals and averages near the bottom of each table show unweighted averages (equal weighting for each company), production-weighted averages (weightings determined by share of total production) or simple totals. Whenever possible, comparable totals and averages from our original report (Q data) are shown on the very bottom row of each table - providing an interesting comparison of the cost structures and production economics from the peak of the previous cycle. Page 2

3 Production Mix, Estimated and Actual Revenue per BOE for U.S. E&Ps Predicted Versus Reported Revenue Oil and Gas Producers Production Mix Oil % in Q2 16 Production Mix Oil % in Q3 14 Predicted Revenue per BOE Q2 16 $45.64/$2.25 Actual Q2 16 Revenue per BOE $45.64/$2.25 Variance Company Ticker Crude Oil Producers Newfield Exploration NFX 45.6% 38.9% $28.16 $28.35 $0.19 Contango Oil & Gas MCF 14.5% 25.1% $18.15 $20.70 $2.55 Laredo Petroleum LPI 46.4% 58.6% $28.41 $ $1.99 Carrizo Oil & Gas, Inc CRZO 57.6% 59.5% $32.03 $32.02 $0.00 SM Energy SM 28.7% 30.5% $22.72 $23.58 $0.86 Diamondback Energy FANG 72.2% 75.1% $36.70 $36.98 $0.28 Sanchez Energy Corp SN 32.1% 47.3% $23.82 $24.80 $0.98 Pioneer Natural Resources Co PXD 57.9% 47.8% $32.11 $ $2.86 Parsley Energy PE 66.4% 52.0% $34.84 $ $1.71 EXCO Resources, Inc XCO 10.0% 9.8% $16.71 $ $0.82 Continental Resources CLR 60.7% 70.1% $33.00 $ $1.45 Energen Corp EGN 60.9% 45.4% $33.07 $36.58 $3.51 Matador Resources Co MTDR 48.2% 56.7% $29.00 $30.56 $1.56 Callon Petroleum CPE 77.4% 81.9% $38.39 $39.20 $0.81 PDC Energy, Inc PDCE 38.3% 45.5% $25.82 $29.10 $3.28 Concho Resources CXO 61.6% 64.1% $33.30 $34.49 $1.19 RSP Permian Inc RSPP 73.2% 76.0% $37.04 $ $0.07 Denbury Resources Inc DNR 96.0% 95.7% $44.37 $45.61 $1.24 Cimarex Energy Co XEC 27.4% 27.6% $22.29 $23.67 $1.38 Resolute Energy Corp REN 78.0% 74.7% $38.56 $ $4.47 EOG Resources, Inc EOG 48.6% 48.8% $29.11 $30.66 $1.55 Bill Barrett Crop BBG 63.7% 41.7% $33.96 $ $2.94 WPX Energy Inc WPX 48.0% 18.2% $28.93 $ $6.23 Devon Energy DVN 40.2% 32.6% $26.43 $ $4.74 EP Energy Corp EPE 53.4% 56.6% $30.65 $30.99 $0.34 Ring Energy Inc REI 89.5% 98.9% $42.27 $ $0.55 Whiting Petroleum Corp WLL 71.2% 79.5% $36.38 $ $1.27 Clayton Williams Energy CWEI 72.4% 72.5% $36.78 $37.67 $0.89 Chesapeake Energy Corp CHK 13.3% 16.3% $17.79 $21.74 $3.95 Bonanza Creek Energy BCEI 55.9% 65.0% $31.45 $ $2.47 Natural Gas Producers Cabot Oil & Gas Corp COG 4.5% 4.0% $14.95 $ $2.27 Range Resources Corp RRC 3.9% 5.3% $14.77 $ $1.93 Antero Resources Corp AR 1.8% 2.1% $14.07 $15.15 $1.07 SouthWestern Energy Co SWN 1.6% 0.2% $14.00 $ $1.25 Rex Energy Corp REXX 3.0% 13.0% $14.46 $ $0.03 Gulfport Energy Corp GPOR 5.5% 14.7% $15.26 $21.26 $6.00 Eclipse Resources Corp ECR 9.6% 12.7% $16.60 $18.55 $1.95 Unweighted Average Production-Weighted Average 32.3% 31.8% $23.89 $ $0.18 Total Q % 31.8% $48.78 $ $2.48 Yellow = Permian Producers Bloomberg, Company Filings and Presentations, Unit Economics Calculations Page 3

4 The Importance of Natural Gas Prices While most analysts consider natural gas a byproduct of crude oil production (24% to 33% of natural gas production is considered associated gas from oil wells, depending on the data source), natural gas prices meaningfully impact overall E&P profitability and cash flows - in addition to well economics - and thus impact crude oil production decisions. The below graphic shows estimated U.S. E&P price realizations (white line, RHS) overlaid with the Energy Select Sector SPDR (XLE) share price (orange line, LHS). Estimated E&P realizations are calculated by simply multiplying.324 by WTI crude oil prices and.676 by Henry Hub natural gas prices (X6 to convert to BOE), approximating the average production mix of U.S. E&Ps. Estimated U.S. E&P Price Realizations per BOE (white line, RHS) versus the XLE Share Price (orange line, LHS) Bloomberg, Unit Economics Calculations As we previously mentioned, our price realization proxy estimated average Q realizations of $23.89/ BOE for the thirty-seven companies analyzed in this report, inline with reported realizations of $23.71/BOE, excluding hedging gains and losses. Second quarter realizations resulted from $45.64/Bbl average WTI crude oil prices and $2.25/MMBtu average HH gas prices. At more recent prices ($47.76/Bbl WTI crude and $3.03/ MMBtu HH gas), we estimate U.S. E&P price realizations have recovered to $27.76/BOE. It is quite interesting to note that increased natural gas prices accounted for $3.16/BOE of the $3.87/BOE increase in realizations since the second quarter, or 81.7%. E&P shares have rallied with natural gas, not crude oil! The matrix on the following page shows estimated average U.S. E&P price realizations for varying WTI crude and HH gas prices. The highlighted boxes show approximate realizations for Q ($47.00/BOE) and Q ($23.71/BOE), as well as estimates for December 2016 ($28.37/BOE) and 2H 2017($28.57/BOE). Page 4

5 HH Natural Gas Prices per MMBtu WTI Crude Oil Prices per Bbl $ 1.25 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 1.50 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 1.75 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2.00 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2.25 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2.50 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2.75 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 3.00 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 3.25 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 3.50 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 3.75 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 4.00 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 4.25 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 4.50 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 4.75 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 5.00 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $23.71 = Q Realizations $28.37 = Estimated December, 2016 Realizations $28.57 = Estimated 2H 2017 Realizations $47.00 = Q Realizations Unit Economics Calculations Estimated Average U.S. E&P Price Realizations Based on Varying Crude Oil and Natural Gas Prices The above matrix shows just how strong a headwind declining natural gas prices will be for U.S. E&Ps: If HH gas averages $2.25/MMBtu in the second half of as we anticipate - WTI crude needs to rally to $59.40/Bbl in order to maintain average price realizations at our December 2016 estimate of $28.37/BOE. If natural gas declines to $2.00/MMBtu, WTI crude needs to rally to $62.54/Bbl to achieve $28.37/BOE realizations. We will publish a 30+ page Natural Gas Market Outlook Report shortly to provide much more insight into our natural gas market views and articulate that it is a matter of when - not if - HH gas moves below $2.50/MMBtu. While U.S. E&P share prices will almost certainly move higher if WTI crude climbs above $60.00/Bbl in 2017, the rally will be muted as increased crude pricing fails to translate into improved revenue or cash flows for producers due to declining natural gas prices and rising service costs, much the same way higher gold prices failed to translate into improved financial performance for gold miners the past cycle. Stating the obvious, we expect shares of the more oily producers (DNR, REI, REN, CPE, RSPP, CWEI, FANG and WLL) to meaningfully outperform the gassy producers (ECR, GPOR, COG, RRC, REXX, AR and SWN). The table on the following page shows the production mix for the companies discussed in this report, sorted from most to least oily. Another strategy will be to create synthetic crude oil pure-plays by buying E&P shares while neutralizing their natural gas exposures via ETFs, which have the benefit of significantly underperforming natural gas: The U.S. Natural Gas Fund, LP (UNG) share price has increased 2.19% YTD despite a 46.02% increase in front-month natural gas futures prices. In coming weeks we will write more extensively about the opportunities in natural gas ETFs - including the publication of a Guide to Flawed Natural Gas ETFs. It is also worthwhile to take a moment to examine the potential impact of lower natural gas prices at the top of the next crude oil cycle: The above matrix estimates that in mid-2014, $95.00/Bbl WTI crude and $4.00/ MMBtu HH gas resulted in U.S. E&P price realizations of $47.00 per BOE (actual Q realizations averaged $46.30/BOE). If we instead assume HH gas will average $2.25/MMBtu in 2018 and beyond, WTI crude needs to climb to $114.74/Bbl in order for U.S. E&Ps to achieve the same $46.30/BOE average price realizations attained in 2014 (when HH gas was $4.00/MMBtu). This math points toward two seemingly conflicting predictions: U.S. E&P price realizations may not reach mid-2014 levels for many years to come, yet we believe WTI crude prices are more likely to return to $100.00/Bbl than most investors anticipate. Page 5

6 Production Mix of U.S. E&Ps Sorted Most to Least Oily Company Ticker Oil Crude and Oil Gas Producers Production Mix Oil % Denbury Resources Inc DNR 96.0% Ring Energy Inc REI 89.5% Resolute Energy Corp REN 78.0% Callon Petroleum CPE 77.4% RSP Permian Inc RSPP 73.2% Clayton Williams Energy CWEI 72.4% Diamondback Energy FANG 72.2% Whiting Petroleum Corp WLL 71.2% Parsley Energy PE 66.4% Bill Barrett Crop BBG 63.7% Concho Resources CXO 61.6% Energen Corp EGN 60.9% Continental Resources CLR 60.7% Pioneer Natural Resources Co PXD 57.9% Carrizo Oil & Gas, Inc CRZO 57.6% Bonanza Creek Energy BCEI 55.9% EP Energy Corp EPE 53.4% EOG Resources, Inc EOG 48.6% Matador Resources Co MTDR 48.2% WPX Energy Inc WPX 48.0% Laredo Petroleum LPI 46.4% Newfield Exploration NFX 45.6% Devon Energy DVN 40.2% PDC Energy, Inc PDCE 38.3% Sanchez Energy Corp SN 32.1% SM Energy SM 28.7% Cimarex Energy Co XEC 27.4% Contango Oil & Gas MCF 14.5% Chesapeake Energy Corp CHK 13.3% EXCO Resources, Inc XCO 10.0% 9.9% Natural Gas Producers Eclipse Resources Corp ECR 9.6% Gulfport Energy Corp GPOR 5.5% Cabot Oil & Gas Corp COG 4.5% Range Resources Corp RRC 3.9% Rex Energy Corp REXX 3.0% Antero Resources Corp AR 1.8% SouthWestern Energy Co SWN 1.6% Page 6

7 U.S. E&P Production Costs - The Income Statement Turning to the cost side of the equation, we begin by examining the current cost structures of U.S. E&Ps as represented by their second quarter income statements. We are admittedly not fans of GAAP accounting for E&Ps, largely due to the way CapEx is treated (very low amortization of property and capital expenditures made worse through periodic, forced write-downs). Not surprisingly, the average U.S. E&P analyzed for this report recorded total second quarter production costs and overhead (SG&A and interest expense) of just $17.16/BOE. This was a 19.2% improvement from the $21.25/BOE average reported in the third quarter of As you can see on the below table, second quarter lifting costs averaged $8.42/BOE, finding costs $2.25/ BOE, production taxes $1.16/BOE, SG&A $2.46/BOE and interest expense averaged $2.86/BOE. The bottom row of the below table shows these respective costs as reported at the top of the previous cycle (Q3 2014). The Income Statement Unit Economics of U.S. E&Ps Production Mix Oil % Reported Q2 16 Revenue per BOE $45.64/$2.25 Reported Lifting Costs per BOE Bloomberg, Company Filings and Presentations, Unit Economics Calculations Reported Finding Costs per BOE Reported Production Taxes Per BOE The 'Unit Economics' Reported SG&A per BOE Reported Interest Expense per BOE Total Reported Income Statement Expenses per BOE Overhead (SG&A + Interest Expense) per BOE Reported CFFO Expenses per BOE Company Ticker Crude Oil and Oil Gas Producers Newfield Exploration NFX 45.6% $28.35 $9.22 $5.77 $0.73 $3.85 $2.52 $22.08 $6.36 $8.06 Contango Oil & Gas MCF 14.5% $20.70 $6.20 $46.68 $0.00 $4.76 $1.04 $58.68 $5.80 $16.51 Laredo Petroleum LPI 46.4% $26.41 $6.27 $0.92 $1.84 $4.73 $5.42 $19.18 $10.15 $7.48 Carrizo Oil & Gas, Inc CRZO 57.6% $32.02 $7.46 $3.14 $1.34 $5.19 $6.92 $24.06 $12.11 $12.93 SM Energy SM 28.7% $23.58 $10.39 $2.84 $0.93 $1.97 $2.38 $18.51 $4.35 $13.89 Diamondback Energy FANG 72.2% $36.98 $8.00 $4.58 $2.43 $2.84 $2.99 $20.85 $5.83 $22.36 Sanchez Energy Corp SN 32.1% $24.80 $10.05 $0.87 $1.22 $4.71 $6.26 $23.10 $10.97 $12.47 Pioneer Natural Resources CoPXD 57.9% $29.24 $8.36 $9.56 $1.70 $3.78 $2.64 $26.04 $6.42 $9.88 Parsley Energy PE 66.4% $33.13 $6.34 $0.00 $1.97 $5.33 $3.85 $17.49 $9.18 $23.31 EXCO Resources, Inc XCO 10.0% $15.89 $8.75 $0.40 $1.08 $3.78 $4.28 $18.29 $8.06 $11.90 Continental Resources CLR 60.7% $31.54 $5.67 $0.95 $1.96 $1.82 $4.10 $14.51 $5.92 $20.58 Energen Corp EGN 60.9% $36.58 $9.26 $4.90 $1.93 $4.03 $1.55 $21.66 $5.58 $19.54 Matador Resources Co MTDR 48.2% $30.56 $9.31 $3.13 $4.14 $5.18 $3.12 $24.88 $8.30 $18.31 Callon Petroleum CPE 77.4% $39.20 $7.98 $0.00 $2.01 $5.15 $3.41 $18.55 $8.56 $21.74 PDC Energy, Inc PDCE 38.3% $29.10 $4.65 $0.00 $1.16 $4.54 $2.05 $12.41 $6.59 $10.50 Concho Resources CXO 61.6% $34.49 $8.34 $7.15 $2.26 $4.04 $4.13 $25.91 $8.17 $24.08 RSP Permian Inc RSPP 73.2% $36.97 $13.66 $0.00 $2.06 $2.58 $5.39 $23.69 $7.97 $20.57 Denbury Resources Inc DNR 96.0% $45.61 $20.36 $0.00 $3.32 $3.84 $7.21 $34.74 $11.05 $35.24 Cimarex Energy Co XEC 27.4% $23.67 $7.83 $0.10 $0.95 $1.96 $1.41 $12.25 $3.37 $14.96 Resolute Energy Corp REN 78.0% $34.09 $18.47 $2.99 $3.93 $6.97 $12.62 $44.98 $19.59 $27.67 EOG Resources, Inc EOG 48.6% $30.66 $8.52 $1.03 $1.86 $1.95 $1.27 $14.63 $3.22 $20.63 Bill Barrett Crop BBG 63.7% $31.02 $7.85 $0.04 $2.19 $6.18 $9.60 $25.86 $15.78 $25.88 WPX Energy Inc WPX 48.0% $19.06 $7.35 $2.02 $2.06 $7.09 $6.84 $25.36 $13.93 $10.16 Devon Energy DVN 40.2% $21.68 $8.38 $4.97 $1.28 $2.51 $3.12 $20.26 $5.63 $15.97 EP Energy Corp EPE 53.4% $30.99 $8.45 $0.38 $1.82 $4.16 $9.49 $24.31 $13.65 $17.34 Ring Energy Inc REI 89.5% $41.71 $13.08 $0.00 $1.77 $9.87 $0.44 $25.16 $10.32 $48.03 Whiting Petroleum Corp WLL 71.2% $35.11 $10.80 $1.02 $2.20 $2.74 $6.44 $23.19 $9.18 $21.93 Clayton Williams Energy CWEI 72.4% $37.67 $15.57 $4.05 $0.00 $10.98 $21.50 $52.09 $32.48 $51.13 Chesapeake Energy Corp CHK 13.3% $21.74 $11.37 $0.48 $0.32 $1.02 $2.08 $15.27 $3.10 $20.15 Bonanza Creek Energy BCEI 55.9% $28.98 $7.10 $0.52 $2.02 $6.26 $7.81 $23.71 $14.07 $34.54 Natural Gas Producers Cabot Oil & Gas Corp COG 4.5% $12.68 $5.65 $0.21 $0.35 $0.80 $0.87 $7.89 $1.67 $9.31 Range Resources Corp RRC 3.9% $12.84 $7.59 $0.52 $0.28 $2.14 $1.75 $12.28 $3.89 $9.02 Antero Resources Corp AR 1.8% $15.15 $8.83 $1.27 $0.65 $2.25 $2.35 $15.37 $4.60 $6.20 SouthWestern Energy Co SWN 1.6% $12.75 $4.61 $0.51 $0.59 $1.49 $1.54 $8.73 $3.04 $10.81 Rex Energy Corp REXX 3.0% $14.43 $8.35 $6.64 $0.00 $1.60 $3.79 $20.39 $5.39 $9.71 Gulfport Energy Corp GPOR 5.5% $21.26 $5.64 $0.00 $0.28 $1.18 $1.73 $8.83 $2.91 $15.41 Eclipse Resources Corp ECR 9.6% $18.55 $9.09 $0.56 $0.57 $2.90 $3.15 $16.28 $6.06 $17.92 Unweighted Average Production-Weighted Average 32.3% $23.65 $8.42 $2.25 $1.16 $2.46 $2.86 $17.16 $5.32 $15.65 Total Q % $46.30 $10.37 $2.96 $2.48 $2.51 $2.92 $21.25 $5.43 $17.63 Yellow = Permian Producers Page 7

8 Since Q3 2014, lifting costs (LOE) have declined by $1.95/BOE while production taxes have declined $1.32/ BOE. Lifting costs tend to follow commodity prices due to both direct linkages (power, fuel for pumps and compression, chemicals, etc.) and indirect linkages (labor, equipment, etc.) and production taxes are directly linked to oil and natural gas prices. Taken together, $3.27/BOE of the $4.09/BOE decline in income statement expenses since Q were in accounts that benefit from lower crude oil and natural gas prices. When E&P price realizations recover, LOEs and production taxes will increase as well. Despite what you read in company presentations, corporate overhead - defined here as SG&A plus interest expense - has not meaningfully declined since Q During Q2 2016, SG&A expenses averaged $2.46/BOE, basically unchanged from $2.51/BOE in Q3 2014, while reported interest expense averaged $2.86/BOE, also unchanged ($2.92/BOE in Q3 2014). The fact that these expenses did not decline on a per-boe basis is not due to declining production: Overall production within our universe has increased 1.1% since Q While interest expense averaged an annualized 5.86% of outstanding principle for the companies we analyzed in Q2 2016, the current average YTM on their outstanding debt is 9.38%. We believe the current yields are justified considering net debt has increased from $66.6 bln in Q to $81.4 bln today while annualized EBITDA declined from $70.7 bln to $23.0 bln (Net Debt:EBITDA has thus increased from.9x to 3.5X). As a result, interest expense will trend upward as older, lower-cost debt matures and is replaced with much more costly paper. E&P Cash Flows Provide a (Slightly) Different View of Costs Because Cash Flows From Operations (CFFO) are derived from income statement accounting, it is not surprising that the table on the previous page shows average reported second quarter cash production expenses of $15.65/BOE (the far right column - Reported CFFO Expenses per BOE ) - not far below the $17.16/BOE average production costs reported on the income statements of the same companies. It is quite interesting to note, however, that income statement expenses for the companies analyzed in this report have decreased by an average of $4.09/BOE since the third quarter of 2014 (from $21.25/BOE to $17.16/ BOE), while production expenses derived from CFFO have declined just $1.98/BOE (from $17.63/BOE to $15.65/BOE). This indicates that perhaps half of the production cost declines since late 2014 are the result of lower non-cash depreciation and amortization, primarily resulting from asset write-downs. For the remainder of this report, we utilize production and overhead expenses derived from cash flow statements to avoid doublecounting a portion of capital expenditures. Production Costs Vary by Oil Intensity Crude oil is more expensive to produce than natural gas: Total reported production + overhead expenses derived from cash flow statements for gassy producers (<10% of production on a BOE basis classified as crude oil) averages $12.82/BOE ($2.14/MMBtu - hence our negative natural gas thesis) while oily producers (crude oil >70% of production) report average cash production + overhead costs of $28.85/BOE. The chart at the top of the following page shows reported second quarter cash production + overhead expenses (per BOE) versus the percentage of production classified as crude oil. Page 8

9 $60.00 Reported Cash Production + Overhead Costs per BOE for Varying Oil Intensities $50.00 Production Costs per BOE $40.00 $30.00 $20.00 $10.00 $ % 10.00% 20.00% 30.00% 40.00% 50.00% 60.00% 70.00% 80.00% 90.00% % Oil as a Percentage of Total Production (BOE Basis) Bloomberg, Company Filings and Presentations, Unit Economics Calculations Reported CapEx and Estimated Maintenance CapEx We estimate maintenance CapEx for each of the thirty-seven companies analyzed in this report by allocating capital spending between spending to offset production declines and spending to increase production. For example, lets assume a hypothetical E&P has a fairly-typical 32% decline rate on their existing production. If the company spent $100 mln on CapEx over the TTM period and reported 16% production growth, we would allocate $66.6 mln of spending to maintenance CapEx and the remainder to growth CapEx. Our late-2014 E&P cost study highlighted that TTM CapEx averaged $36.94/BOE on a production-weighted basis and we estimated maintenance CapEx was $31.61/BOE at the time. We also speculated that a 20% decline in service costs, consistent with previous cycles, would reduce maintenance CapEx to $25.29 per BOE. Fast forward to Q and we find TTM CapEx averaged $17.26/BOE and estimated maintenance CapEx was just $18.18/BOE - a decline of 42.4% from Q Interestingly, twelve of the thirty-seven companies analyzed for this report (32.4%) are effectively holding production flat (+/- 5%) and average YOY production growth for all thirty-seven companies was +1.4% during the second quarter. As a result, reported TTM CapEx ($17.26/BOE) is a reasonable approximation of maintenance Capex - although most companies are modestly benefitting from previous spending, particularly on wells that sit uncompleted and the construction of gathering and processing capacity to meet planned production growth that never materialized. Page 9

10 Estimated Maintenance CapEx per BOE and FCF Breakeven WTI Crude Price (Based on $2.60 HH Natural Gas) TTM Capex to 2016 Revenue Maintenance CapEx Analysis Cons Forecasted 2016 Revenue (mln) TTM CapEx as a % of Cons 2016 Revenue TTM Production Growth Estimated Maintenance CapEx per BOE Estimated FCF Breakeven WTI Price at $2.60 Gas Oil and Gas Producers Company Ticker Production Mix Oil % TTM CapEx (mln) TTM Capex per BOE Crude Oil Producers Newfield Exploration NFX 45.6% $1,673 -$1, % -$ % -$22.99 $36.75 Contango Oil & Gas MCF 14.5% $82 -$ % -$ % -$20.66 $37.16 Laredo Petroleum LPI 46.4% $599 -$ % -$ % -$22.43 $39.70 Carrizo Oil & Gas, Inc CRZO 57.6% $538 -$ % -$ % -$24.88 $40.66 SM Energy SM 28.7% $1,239 -$ % -$ % -$24.68 $42.41 Diamondback Energy FANG 72.2% $481 -$ % -$ % -$28.29 $46.92 Sanchez Energy Corp SN 32.1% $579 -$ % -$ % -$18.63 $49.04 Pioneer Natural Resources Co PXD 57.9% $3,082 -$2, % -$ % -$17.61 $49.63 Parsley Energy PE 66.4% $481 -$1, % -$ % -$28.88 $50.13 EXCO Resources, Inc XCO 10.0% $310 -$ % -$ % -$19.11 $53.41 Continental Resources CLR 60.7% $2,147 -$1, % -$ % -$23.55 $53.55 Energen Corp EGN 60.9% $570 -$ % -$ % -$34.28 $53.82 Matador Resources Co MTDR 48.2% $286 -$ % -$ % -$37.16 $55.47 Callon Petroleum CPE 77.4% $217 -$ % -$ % -$18.94 $55.85 PDC Energy, Inc PDCE 38.3% $595 -$ % -$ % -$9.06 $56.05 Concho Resources CXO 61.6% $2,216 -$1, % -$ % -$32.71 $56.79 RSP Permian Inc RSPP 73.2% $346 -$ % -$ % -$42.79 $58.45 Denbury Resources Inc DNR 96.0% $1,013 -$ % -$ % -$23.37 $58.60 Cimarex Energy Co XEC 27.4% $1,273 -$ % -$ % -$14.93 $58.69 Resolute Energy Corp REN 78.0% $244 -$ % -$ % -$27.38 $58.91 EOG Resources, Inc EOG 48.6% $7,201 -$3, % -$ % -$17.69 $58.94 Bill Barrett Crop BBG 63.7% $262 -$ % -$ % -$35.01 $60.89 WPX Energy Inc WPX 48.0% $1,190 -$1, % -$ % -$16.65 $61.72 Devon Energy DVN 40.2% $10,057 -$3, % -$ % -$16.61 $64.23 EP Energy Corp EPE 53.4% $1,281 -$ % -$ % -$80.38 $69.12 Ring Energy Inc REI 89.5% $33 -$ % -$ % -$32.05 $69.98 Whiting Petroleum Corp WLL 71.2% $1,434 -$1, % -$ % -$56.76 $70.04 Clayton Williams Energy CWEI 72.4% $155 -$ % -$ % -$34.86 $71.96 Chesapeake Energy Corp CHK 13.3% $8,288 -$2, % -$ % -$11.66 $72.13 Bonanza Creek Energy BCEI 55.9% $203 -$ % -$ % -$44.21 $78.76 Natural Gas Producers Cabot Oil & Gas Corp COG 4.5% $1,261 -$ % -$ % -$3.60 NA Range Resources Corp RRC 3.9% $1,573 -$ % -$ % -$6.36 NA Antero Resources Corp AR 1.8% $2,417 -$1, % -$ % -$11.73 NA SouthWestern Energy Co SWN 1.6% $2,408 -$1, % -$ % -$9.11 NA Rex Energy Corp REXX 3.0% $157 -$ % -$ % -$13.53 NA Gulfport Energy Corp GPOR 5.5% $694 -$ % -$ % -$11.05 NA Eclipse Resources Corp ECR 9.6% $224 -$ % -$ % -$8.69 NA Unweighted Average Production-Weighted Average 32.3% $4,064 -$1, % -$ % -$18.18 $59.26 Total Q % $10,056 -$4, % -$ % -$31.61 $ Yellow = Permian Producers Bloomberg, Company Filings and Presentations, Unit Economics Calculations Page 10

11 Total Cash Production Costs The far right column on the table on the previous page combines our previously-calculated Reported CFFO Expenses per BOE with our maintenance CapEx estimates to determine our best estimate of the WTI crude oil price where companies could maintain current production and be FCF-neutral. Our scenario is based on $2.60/MMBtu HH gas, which we believe is a reasonable estimate for the average price in 2017 ($3.50/MMBtu in Q1 falling to $2.00/MMBtu by late fall). We believe Newfield Exploration (NFX) was the lowest cost crude oil producer during the second quarter ($36.75/Bbl) and Bonanza Creek Energy (BCEI) was the highest cost ($78.76/BOE). Overall, we calculate cash crude production costs averaged $59.26/Bbl in Q2 2016, a 42.0% decline from the $102.22/Bbl average of Q Apache Corp Reports North American Well Costs Down 45% from 2014 Page thirty two of this report shows a recent slide from Apache Corp (APA), indicating their North American well costs have declined 45% since inline with the 42.4% decline in costs the companies analyzed for this report have enjoyed since the third quarter of The Apache Corp slide further breaks down their cost reductions by showing service costs have decreased 21% since 2014 while design and efficiency savings have reduced well costs by 24%. We believe the service cost reductions of the past two years are already reversing and will continue to do so over the next two to three years, resulting in a 25% increase in well costs (to return to prior levels), but how should we think about design and efficiency gains? Analyzing U.S. Oil Rig Productivity Trends In their monthly Drilling Productivity Report, the EIA provides estimated monthly new oil and gas production for seven major producing regions across the United States on a per-rig basis, as well as legacy production data and decline rates. To calculate new-well oil production per rig the EIA uses several months of recent IP30 well data to estimate average production per rig (IP30 X wells drilled), lagged by two months in order to incorporate the typical time between drilling and initial well production (which is how they can already show December production data - it is based on October drilling activity). The raw EIA productivity data is a major driver of our natural gas productivity models, which when combined with our rig count estimates and price-sensitive demand models have helped us forecast annual natural gas prices since 2009 with an average forecast error of $-.16 ($1.14 cons) and an average absolute forecast error of $.41 ($1.14 cons). This explains why we believe the best oil analysts the next few years will actually be natural gas analysts: Gas analysts understand rig productivity trends! An accurate rig productivity model (crude oil or natural gas) incorporates three primary components: The geographical distribution of drilling rigs, long-term technological/productivity trends and the rig count itself (the more rigs drilling, the less productive the marginal rig). Modelling the Impact of the Geographical Distribution of Drilling Rigs While the geographical distribution of U.S. drilling rigs tends to remain fairly constant, 2016 is proving to be an exception: The Bakken and Eagle Ford are losing meaningful share to the Permian - where 51.77% of rigs operating in major basins are employed (up from 41.90% in 2015), as you can see on the following table: Page 11

12 IEA, Bloomberg, Unit Economics Calculations U.S. Drilling Rig Allocation by Basin (ytd) Bakken 13.43% 14.95% 16.57% 15.79% 14.56% 12.76% 9.48% Eagle Ford 13.02% 16.99% 21.29% 22.27% 20.73% 19.32% 13.99% Haynesville 25.81% 12.75% 5.26% 3.93% 4.10% 5.44% 5.83% Marcellus 12.45% 11.18% 8.90% 7.53% 6.67% 9.13% 8.78% Niobrara 6.84% 7.27% 6.55% 7.67% 8.00% 7.70% 6.28% Permian 27.88% 36.18% 40.02% 40.18% 42.72% 41.90% 51.77% Utica 0.57% 0.68% 1.41% 2.63% 3.22% 3.75% 3.85% Total % % % % % % % Average Rigs 867 1,170 1,240 1,154 1, Based on company presentations and widely-touted well results (2,000 to 3,000+ BOE/d IP30s most recently), it would appear an increased share of rigs operating in the Permian is positive for oil productivity per rig. To the contrary, Permian wells are prolific - but very gassy overall: Crude oil accounts for just 25.8% of current Permian production. Even lowly Bakken wells produce more barrels of oil per day. We can estimate the impact of this year s increase in the share of rigs operating in the Permian by comparing the reported year-to-date EIA oil productivity data to a rig productivity model which redistributes the current rig count based on the geographic distribution of rigs in the prior year. Based on these calculations, we believe the change in the geographical distribution of rigs in 2016 has reduced the oil productivity of the average onshore rig by 14.06%. For comparison purposes, the following table utilizes the same methodology to estimate the annual impact of changing rig allocations from 2011 to 2016: Change in Crude Oil Production per Rig Attributable to Geographical Shifts (ytd) % -2.14% 5.32% -3.10% 4.62% % IEA, Bloomberg, Unit Economics Calculations Put differently, the oil productivity of the current 474 oil-directed onshore rigs would be equaled by just 407 rigs had the geological distribution remained unchanged from Going forward, when crude oil prices recover and the Permian loses share to other producing regions (the Permian rig count will increase, but rig counts in other regions are likely grow more quickly off of a lower base), average rig productivity will increase as rigs drilling in other regions produce more crude oil than the average Permian rig, as we show on the table on the following page. The Technological and Productivity Trends of U.S. Oil Rigs In mid-2010 we wrote of the disruptive technology of horizontal drilling and how the resulting 3X jump in natural gas rig productivity would depress U.S. natural gas prices for at least a decade. Horizontal drilling has since been credited as the most important technological innovation of the past decade and natural gas prices declined from an average of $7.12/MMBtu in 2007 to $2.45/MMBtu so far in 2016 (UE 2016 forecast: $2.45/MMBtu). Page 12

13 The impact of horizontal drilling was much less profound for oily wells, largely due to the relative difficulty of moving viscous liquids into a wellbore. That said, U.S. crude oil producers have benefitted from a steady stream of innovations and new technologies over the past decade, including longer laterals, geosteering, more capable land rigs, improvements in proppant and fluids, pad drilling, closer frack stage spacing and more recently higher proppant concentrations. The following table shows the average annual new oil production per rig (IP30) from 2010 through 2016 (ytd) for the Bakken, Eagle Ford, Niobrara and Permian: IEA, Bloomberg, Unit Economics Calculations New Crude Oil Production per Rig, Bbl/d Current (ytd) CAGR CAGR CAGR YOY Bakken % 23.5% 36.4% 33.0% Eagle Ford % 38.9% 36.2% 19.3% Niobrara % 45.4% 54.0% 26.3% Permian % 32.9% 65.4% 32.1% Weighted Averag % 33.8% 53.8% 28.9% Average Rigs , , The right four columns on the above table show the compounded annual growth in new oil production per rig for varying timeframes. Overall, from 2010 to 2016 crude oil production per rig increased by an average of 33.2% per year - a very significant amount! The table also shows that over this six year period, rig productivity improvements varied significantly by region, with Bakken rigs enjoying relatively muted productivity growth of 21.3% per year while rigs operating in the Eagle Ford enjoyed 48.7% annual productivity gains - resulting in a 10X increase in new oil production per Eagle Ford rig over just six years. The above table also shows that from rig productivity grew 33.8% annually, inline with the average. The period is rather important as the U.S. onshore rig count (bottom row on the above table) was quite steady over this period, mitigating the productivity impact of changing rig counts. Fast forward to , a period during which the U.S. oil-directed rig count plunged from 1,499 to the current 474 rigs, and we find per-rig productivity increased a stunning 53.8% per year over these two years. The Productivity Impact of Changes in the Rig Count As we previously mentioned, the third major factor for rig productivity (behind the geographical distribution and technological trends) is the rig count itself: When oil prices plummet and the rig count contracts sharply, operators high-grade their assets, focusing rigs on their most productive well sites. This creates the appearance of productivity gains (the average rig does in fact produce more crude oil), but in reality the most productive well sites do not enjoy a surge in productivity - they simply grow in proportion to the total number of wells drilled. Despite being based on some simple math, we find there is very little understanding of how overall rig productivity is impacted by dramatic changes in the rig count. As a result, sell-side analysts often rely upon incredibly flawed calculations when attempting to determine the breakeven (production-maintaining) oil rig count (usually 900+ rigs versus our calculation of 655 in 2016 falling to 445 by the end of 2017). Page 13

14 If we examine a hypothetical scenario where 1,600 rigs are operating and they can be divided into quartiles based on their monthly oil productivity (200 bpd, 400 bpd, 600, bpd and 800 bpd), we could easily calculate that the average rig produces 500 bpd of new oil per month. If the rig count were to suddenly decline to 400 rigs, with only the most productive rigs remaining in operation, the oil productivity per rig would increase 60% to 800 bpd. As we previously mentioned, highest productivity rigs continue to produce the same amount of new oil (800 bpd/month), but their share in the overall mix increases from 25% to 100%. Assuming for a moment there is no underlying rig productivity growth (technological improvements and drilling innovations cease), if the rig count were to remain unchanged at 400 rigs, the average rig s oil productivity would remain at 800 bpd and thus productivity growth would fall from +60% to zero after twelve months. If the rig count were to recover to 800 rigs, with the incremental 400 rigs producing 600 bpd in the first month, the oil productivity of the average rig would decline 12.5% to 700 bpd (( ) / 2). Turning back to the New Crude Oil Production per Rig table on the previous page, we find that rig productivity increased 53.8% per year during the period, well above the 33.8% annual productivity growth rate observed from , a period during which the U.S. onshore rig count remained relatively stable. Looking at the far right column on the table on the previous page, we see onshore rig oil productivity is currently up 28.9% from the prior year, basically inline with long-term trends. This is not surprising given the more stable rig count and the rig productivity math discussed in the previous paragraph. When oil prices recover and the U.S. rig count increases, the long-term productivity trend (+33% per year) will be partially or even completely offset by the mathematical decrease in per-rig productivity as less productive rigs return to less productive acreage. This will, of course, be a temporary phenomena. Two illustrative graphics from the EIA s Drilling Productivity Reports are shown below. The left shows the Bakken rig count (black line) and rig productivity (orange line) from 2007 to 2014, while the right graphic shows Bakken rigs and productivity from 2007 to Notice the sharp decline in the Bakken rig count in 2009 and the resulting surge in rig productivity, followed by a two year period of declining rig productivity as the Bakken rig count increased to new highs. More recently, Bakken rig productivity has roughly doubled since mid-2014 as the Bakken rig count declined from a peak of 194 rigs to just 31 today (right graphic). Bakken Rig Counts and Rig Productivity EIA Drilling Productivity Report, 2014 EIA Drilling Productivity Report Page 14

15 Are U.S. Land Rig Owners Doomed? Yep Assuming oil rig productivity continues to increase 33% per year, the 1,600 rigs needed to grow U.S. crude oil production by one million bpd in 2013/14 would evolve into just 144 rigs in 2020 (that s not a typo!). Similar calculations show IP30s from 10,000 ft lateral wells at the best locations (currently the Delaware) would average roughly 7,000 bpd in 2020, as unbelievable as this seems today! Keep in mind that in 2012, U.S. lower 48 natural gas production was maintained at 70 BCF/d with an average of 542 gas-directed rigs, while we calculate just 105 gas-directed rigs can maintain production at 79 BCF/d today. As we often stated when discussing the implications of horizontal drilling on natural gas production several years ago, we aren't predicting productivity trends, we are reporting them! As a side story, there is a well-known London investment firm (which will remain nameless) that we visit every couple years, usually with the goal of determining consensus European views (they have never been and will never be clients, I can assure you). When we met their star natural gas PM several years ago we heard the word bullocks more times in one meeting than Rob and I had in our lives. The PM no longer works for the firm. Six weeks ago we met with the same firm and received a similarly-hostile (but less profane) response to our views on the long-term implications of oil rig productivity trends. We found this to be very re-assuring! Is New Oil Production per Rig Representative of Supply? One of the common counter-arguments to any analysis based on the EIA s rig productivity data is that they calculate rig productivity based on IP30 rates rather than IP360 rates or (even better) the Estimated Ultimate Recovery (EUR) from wells. Unfortunately, IP360 rates are much harder to come by than IP30 rates (and IP360s can include production increases resulting from workovers), while EUR estimates are often subject to long-term commodity price and cost assumptions (used to determine the productive lives of wells in the calculations). There really are no perfect productivity measures. That said, based on EUR estimates and production type curves reported by public companies, we estimate EURs have increased roughly inline with IP30 rates, with average IP30s for oily wells (>50% of BOEs) increasing 41% annually from 2013 through 2015 while EURs from newly-drilled (and oily) wells increased 32% per year. Using IHS data from the Bakken, Eagle Ford and Permian we are also able to calculate IP30s increased 25.0% annually from 2010 through 2014 while EURs increased 18.2% annually. We believe the annual growth rate in EURs was roughly 7% to 9% per year below the growth rate in IP30s. Translating Rig Productivity into Well Costs The EIA commissioned IHS Global Inc (IHS) to produce a well cost study in 2014, the results of which were published by the EIA in March, 2016 in an excellent report entitled Trends in U.S. Oil and Natural Gas Upstream Costs. The 131 page report shows that proppant use per lateral foot increased from 200 to 400 lbs in 2008 to 400 to 1,600 lbs in 2014 (1,000 to 1,600 lbs excluding the Bakken), while the average number of frack stages nationally increased from roughly 10 stages per well in 2009 to 24 stages per well in The charts on the following page show the amount of proppant per lateral foot by production region and year (left chart), as well as the amount of fluid, proppant and frack stages for the average North American well (right chart). Page 15

16 The EIA/IHS report and above charts show that much of the well productivity gains since 2008 can be attributed to enhanced completions - completions that are heavily-reliant on proppant and fluid intensity, as well as increased frack stage counts. As a result, total well costs (CapEx per well) have increased over the past few years in most cases, despite more recent declines. Looking at well costs per BOE produced, the EIA/ IHS data shows well costs declined from approximately $21.75/BOE in 2010 to $19.00/BOE in as the following EIA/IHS graphic displays: Despite roughly 25.1% annual rig productivity growth from 2010 through 2014, well costs declined a total of 12.6%. Note that well costs do not include processing, gathering, engineering and corporate overhead. Including cost inflation in these categories, it is likely that capital costs per BOE actually increased modestly from 2010 through Technological improvements often do not lead to unit cost improvements! Page 16

17 E&P Investment Themes for 2017 Revisiting our E&P Baskets from 2014 In late 2014 we examined the cost structures and production economics of U.S. E&Ps in a report entitled Are U.S. Crude Oil Production Costs $20, $55 or $100? Yes! The report concluded that lenders will limit oil production growth, not E&P Management, stating: Investors (and banks) have shown an amazing willingness to loan funds to cash-burning E&Ps at relatively low interest rates over the past few years amid a Fed-induced quest for yield. This has prompted many, including OPEC leaders, to label U.S. shale oil production growth a bubble as cheap credit has allowed U.S. E&Ps to grow production even as their existing operations burn cash at extraordinary rates. Frankly, this sounds more like a Ponzi scheme than a bubble. Despite claiming 40%+ IRRs, when was the last time an E&P company repaid a debt maturity from cash flows, rather than from increased borrowing? Not surprisingly, we believed the relative performance of upstream energy companies would be determined by their cost structures and ability to borrow funds amidst a downturn in commodity prices. The report went on to show five E&Ps (REXX, XCO, UPL, MHR and BBG - the Floundering Five ) were facing imminent liquidity concerns and were thus likely bankruptcy candidates. The average share price of the five companies has since declined 70.1% as two have gone bankrupt (UPL and MHR) and two more will likely file for bankruptcy shortly (REXX and XCO). A second group contained nine E&Ps (SFY, PDCE, LPI, RRC, SD, ROSE, DNR, WPX and NFX) predicted to reach critical debt levels within a year (the Naked Nine ). The average share price of the Naked Nine companies has since declined 21.5% and two have since declared bankruptcy (SFY and SD). A third grouping, the Safe Seven (MCF, CLR, EOG, FANG, PXD, WLL and XEC), was rated favorably due to low production costs, low debt burden and relatively little cash burn. The average share price of these seven companies has declined just 1.5% since December, Over the same period, shares of the Energy Select Sector Spider (XLE) declined a total of 13.1%, as can be seen on the chart on the following page. Current E&P Capital Structures and Sources of Liquidity Quite surprisingly, the total Enterprise Value of the thirty seven companies analyzed for this report has actually increased slightly since December, 2014 (from $353.9 bln to $355.6 bln), despite annualized EBITDA collapsing from $63.5 bln to just $20.5 bln. Over the same period, the average share price of the same companies has declined 16.79%, while the total market cap declined just 4.92% due to increased share counts resulting from new equity issuance ($13.6 bln), acquisitions utilizing equity and stock options programs. This has left our universe with a total market cap of $274.2 bln ($288.3 bln in December, 2014), gross debt of $93.6 bln ($79.1 bln in December, 2014) and cash balances totaling $12.2 bln ($12.5 bln in December, 2014). Net Debt:EV is currently 34%, up from 29% in December, Page 17

18 The Price Performance of the Floundering Five, Naked Nine, Safe Seven and the Energy Select Sector Spider ETF (XLE) Since December, 2014 Page 18

19 Over the past twelve months, the thirty-seven E&Ps we analyzed reported total revenue of $56.8 bln and total EBITDA of $23.1 bln. Despite this, they issued $13.6 bln of equity and disposed of $7.2 bln of assets. In fact, according to the slide from ENERCOM Consulting shown on pg. 34 of this report, 2016 is already a record year for follow-on equity offerings and a record-low year for debt issuance (both since 2011). U.S. E&Ps have used equity offerings and asset sales to cover losses from operations, as well as repay corporate debt - repayments which we highly-doubt were voluntary. The following table shows these calculations: U.S. E&P Sources of Liquidity and Financing TTM Net Borrowing (mln) Sources of Liquidity and Financing TTM Issuance of Capital Stock (mln) TTM Disposal of Fixed Assets (mln) Bloomberg, Company Filings and Presentations, Unit Economics Calculations Total TTM Issuance + Asset Disposal + Borrowing (mln) Financing Needs Coming 12 Months at Maintenance CapEx and $2.60/$60.00 (mln) Financing Needs in Coming 12 Months Current EV Company Ticker Oil and Crude Gas Oil Producers Newfield Exploration NFX -$143 $760 $90 $707 $ % Contango Oil & Gas MCF $1 -$1 $0 $0 $ % Laredo Petroleum LPI $6 $118 $66 $189 $12 0.3% Carrizo Oil & Gas, Inc CRZO -$2,209 $239 $22 -$1,948 $32 0.9% SM Energy SM $131 $4 $36 $171 $1, % Diamondback Energy FANG -$396 $456 $10 $69 $89 1.1% Sanchez Energy Corp SN -$52 $0 $0 -$52 $ % Pioneer Natural Resources Co PXD -$2,087 $2,542 $551 $1,006 NONE 0.0% Parsley Energy PE -$278 $1,105 $50 $877 $ % EXCO Resources, Inc XCO -$191 $10 $11 -$169 $ % Continental Resources CLR $137 $13 $114 $264 $ % Energen Corp EGN -$444 $382 $287 $225 $ % Matador Resources Co MTDR $55 $142 $140 $337 $ % Callon Petroleum CPE -$45 $411 $24 $390 NONE 0.0% PDC Energy, Inc PDCE -$278 $292 $5 $19 NONE 0.0% Concho Resources CXO -$813 $782 $294 $264 $ % RSP Permian Inc RSPP $198 $394 $1 $593 $ % Denbury Resources Inc DNR -$425 -$12 $0 -$437 $21 0.5% Cimarex Energy Co XEC $202 $18 $45 $265 $ % Resolute Energy Corp REN -$188 $0 $228 $40 $33 3.5% EOG Resources, Inc EOG $1,172 -$11 $329 $1,491 $1, % Bill Barrett Crop BBG -$80 $0 $57 -$24 $ % WPX Energy Inc WPX $18 $1,172 $1,300 $2,490 NONE 0.0% Devon Energy DVN $664 $2,266 $308 $3,238 $1, % EP Energy Corp EPE -$974 -$2 $391 -$585 $1, % Ring Energy Inc REI -$43 $62 $0 $19 $20 4.5% Whiting Petroleum Corp WLL -$509 $0 $211 -$298 $1, % Clayton Williams Energy CWEI $33 $17 $44 $94 $ % Chesapeake Energy Corp CHK $152 $0 $1,289 $1,441 $5, % Bonanza Creek Energy BCEI $51 $0 $0 $51 $ % Natural Gas Producers Cabot Oil & Gas Corp COG -$958 $995 $54 $91 $ % Range Resources Corp RRC -$897 $11 $1,067 $182 $ % Antero Resources Corp AR -$141 $993 $0 $852 $1, % SouthWestern Energy Co SWN $267 $0 $80 $347 $2, % Rex Energy Corp REXX $13 $0 $73 $85 $ % Gulfport Energy Corp GPOR $122 $411 $28 $561 $ % Eclipse Resources Corp ECR $205 $0 $17 $222 $ % Unweighted Average 10.94% Production-Weighted Average Total -$7,727 $13,569 $7,223 $13,065 $25,170 Yellow = Permian Producers Going forward, we calculate the thirty seven companies we analyzed would need to raise $25.17 bln over the coming twelve months in order to maintain production in an environment of $60.00/Bbl WTI crude and $2.60/ MMBtu HH gas (see the second column from the right). These calculations include the anticipated increases in LOE, taxes and capital expenditures associated with higher crude oil prices as well as lower hedge book coverage. The far-right column on the above table shows that in aggregate, the average U.S. E&P would need to Page 19

20 raise 10.94% of their current enterprise value. While this is not insurmountable, eight of the thirty-seven companies need to raise in excess of 25.00% of their current EV in our scenario (MCF, SM, SN, XCO, BBG, EPE, WLL, and BCEI). This should prove difficult, to say the least. On the opposite end of the spectrum, there are four companies we believe would generate small amounts of FCF in our $60.00/$2.60 scenario (PXD, CPE, PDCE and WPX) and an additional thirteen companies would need to raise less than 5.00% of their current EVs over the coming twelve months (NFX, LPI, CRZO, FANG, PE, CLR, CXO, RSPP, DNR, REN, EOG, DVN and REI). We will utilize this criteria as one of the inputs in the construction of new equity baskets a little later in this report. Borrowing Ability and Bankruptcy Risk The majority of the companies we analyzed currently have either negative EBITDA (eleven of the thirtyseven) or debt in excess of 3X EBITDA (also eleven of thirty-seven), as the following table displays: Gross Debt (mln) Bloomberg, Company Filings and Presentations, Unit Economics Calculations Borrowing Ability and Financial Health of U.S. E&Ps Enterprise Value Enterprise Value (mln) Quarterly FCF at Maintenance CapEx and $60.00/$2.60 Financing Needs Coming 12 Months at Maint CapEx and $60.00/$2.60 Financing Needs at $60.00/$2.60 as a % of Current EV Forecasted EBITDA at $60.00/$2.60 Borrowing Ability Current Net Debt to Forecasted EBITDA at $60.00/$2.60 Remaining 2016 Hedge Value (Gain in Mln at $60 WTI and $2.60 HH) in mln 2017 Hedge Value (Gain in Mln at $60 WTI and $2.60 HH) in mln Corp Bond Yield to Maturity Altman Z- Score (<1.81 = Distressed) Company Ticker Market Cap (mln) Cash (mln) Net Debt:EV Oil and Gas Producers Newfield Exploration NFX $8,631 $2,430 $165 $10,896 22% -$34 $ % $1, $45 $ % Contango Oil & Gas MCF $252 $115 $0 $367 31% -$30 $ % $41 NEG EBITDA -$1 $ Laredo Petroleum LPI $3,098 $1,392 $19 $4,470 31% -$3 $12 0.3% $ $68 $ % Carrizo Oil & Gas, Inc CRZO $2,396 $1,298 $2 $3,691 35% -$8 $32 0.9% $ $0 $ % SM Energy SM $3,351 $2,603 $0 $5,954 44% -$279 $1, % $ $131 $ % 0.58 Diamondback Energy FANG $7,533 $496 $219 $7,810 6% -$22 $89 1.1% $ $10 $ % 3.43 Sanchez Energy Corp SN $851 $1,747 $324 $2,274 77% -$51 $ % $ $101 $ % Pioneer Natural Resources CPXD $31,488 $3,664 $3,298 $31,854 12% $177 NONE 0.0% $2, $206 $1, % 2.92 Parsley Energy PE $6,921 $744 $441 $7,224 10% -$37 $ % $ $0 $ EXCO Resources, Inc XCO $303 $1,324 $28 $1,599 83% -$102 $ % $23 NEG EBITDA $11 $ % Continental Resources CLR $19,462 $7,118 $17 $26,563 27% -$134 $ % $2, $57 $0 5.65% 0.94 Energen Corp EGN $5,603 $551 $310 $5,844 9% -$95 $ % $ $85 $ % 0.88 Matador Resources Co MTDR $2,271 $392 $0 $2,663 15% -$64 $ % $ $0 $ % Callon Petroleum CPE $2,546 $329 $0 $2,874 11% $8 NONE 0.0% $ $9 $ % PDC Energy, Inc PDCE $3,693 $495 $109 $4,079 12% $26 NONE 0.0% $ $86 $ % 1.65 Concho Resources CXO $19,337 $3,332 $481 $22,188 15% -$249 $ % $1, $164 $ % 1.92 RSP Permian Inc RSPP $3,942 $687 $33 $4,596 15% -$45 $ % $ $0 $ % 1.57 Denbury Resources Inc DNR $1,287 $3,082 $3 $4,366 71% -$5 $21 0.5% $ $76 $ % Cimarex Energy Co XEC $12,763 $1,487 $642 $13,609 11% -$171 $ % $ $8 $0 4.87% 1.04 Resolute Energy Corp REN $402 $547 $0 $948 58% -$8 $33 3.5% $ $36 $ % EOG Resources, Inc EOG $53,253 $6,986 $780 $59,459 12% -$393 $1, % $3, $7 $ % 1.71 Bill Barrett Crop BBG $335 $712 $87 $959 74% -$35 $ % $ $37 $ % WPX Energy Inc WPX $4,892 $2,732 $1,031 $6,593 41% $26 NONE 0.0% $ $7 $ % Devon Energy DVN $23,096 $12,707 $1,723 $34,080 37% -$404 $1, % $4, $286 $1, % EP Energy Corp EPE $1,106 $3,929 $39 $4,996 79% -$496 $1, % $1, $221 $ Ring Energy Inc REI $459 $0 $8 $451 0% -$5 $20 4.5% $20 NEG EBITDA $0 $ Whiting Petroleum Corp WLL $2,407 $4,691 $15 $7,083 66% -$431 $1, % $1, $0 $ % Clayton Williams Energy CWEI $1,471 $930 $158 $2,243 41% -$52 $ % $ $31 $0 8.88% 0.23 Chesapeake Energy Corp CHK $7,934 $9,649 $4 $17,579 55% -$1,294 $5, % $798 NEG EBITDA -$197 $9 8.20% Bonanza Creek Energy BCEI $51 $1,055 $170 $ % -$93 $ % $ $7 $ % Natural Gas Producers Cabot Oil & Gas Corp COG $12,001 $1,539 $517 $13,022 12% -$196 $ % $914 NEG EBITDA -$25 $0 3.32% 2.05 Range Resources Corp RRC $9,577 $2,567 $0 $12,143 21% -$227 $ % $671 NEG EBITDA $109 $ % 0.57 Antero Resources Corp AR $8,279 $4,244 $28 $12,494 34% -$381 $1, % $1,349 NEG EBITDA $382 $1 5.49% 0.99 SouthWestern Energy Co SWN $8,554 $5,768 $998 $13,324 43% -$617 $2, % $948 NEG EBITDA $0 $0 6.69% Rex Energy Corp REXX $217 $779 $3 $992 79% -$57 $ % -$35 NEG EBITDA $11 $ % Gulfport Energy Corp GPOR $3,542 $957 $396 $4,102 23% -$209 $ % -$506 NEG EBITDA $79 $ % Eclipse Resources Corp ECR $857 $491 $114 $1,234 40% -$66 $ % -$8 NEG EBITDA $9 $ % Unweighted Average 9.38% (0.96) Production-Weighted Average 34% 11.18% Total $274,158 $93,569 $12,165 $355,562 -$6,056 $25,169 $31,408 $1,048 $7,111 Q $288,335 $79,128 $12,505 $354,958 29% -$12,671 $50, % NA - - $5, % 1.55 Yellow = Permian Producers Page 20

21 The table on the previous page also shows that the average corporate debt YTM for the thirty-seven companies is 9.38% and four companies (XCO, BBG, BCEI and REXX) have debt yielding in excess of 15.00% - a key level signaling significant bankruptcy risk. In our December, 2014 report four companies had debt with an average Yield-to-Maturity >15.00% (SFY, XCO, SD and MHR). Of these four, only EXCO Resources (XCO) is yet to file bankruptcy - but they are currently in negotiations to restructure debt and their auditors have issued a going concern statement. Altman Z-scores are also a key indicator of bankruptcy risk: In December, 2014 the average Altman Z-score of the companies we analyzed was 1.55 and seven companies had Z-scores below 1.00 (<1.81 = distressed ) - SFY, REXX, XCO, WPX, SD, UPL, LPI and BBG. Three have since declared bankruptcy (SFY, SD, UPL) and two should file in coming weeks (XCO and REXX). Fast forward to 2016 and we find OPEC has accomplished their mission of financially crippling U.S. E&Ps: The average Z-score of the thirty-seven companies analyzed for this report is.96 and just ten companies have Z-scores greater than 1.00 (FANG, PXD, PE, PDCE, CXO, RSPP, XEC, EOG, REI and COG). Valuation Metrics and the Permian Bubble Before we discuss our new stock baskets, we will first spend a few moments looking at valuation metrics for our U.S. E&P universe. Due to the lack of earnings and cash flows, typical earnings-based valuation metrics are of little use. For example, the group currently trades at 15.46X annualized EV:EBITDA, up from 5.02X in late Looking at other metrics, the production-weighted EV per flowing barrel for the group has actually increased from $55,796 in December, 2014 to $67,722 today. Even more surprising, the eight Permian producers highlighted in yellow on our tables (LPI, FANG, PE, CPE, CXO, RSPP, REN and REI) are trading at an average EV per flowing barrel of $167,423. The remaining twenty-nine companies are valued at $64,481 per flowing barrel. A similar divergence appears when examining other metrics. Looking at EV to proved reserves, the thirtyseven companies analyzed are valued at an average of $18.35 per BOE of proved reserves, up from $14.42 per BOE in December Excluding the eight Permian producers, which are valued at an average of $38.53 per BOE of proved reserves, we find the remaining companies are valued at $17.40 per BOE. The biggest divergence comes when examining EV per acre, where the thirty-seven companies are valued at an EV of $8,469 per acre ($3,666 in December, 2014), while the Permian producers are valued at a stunning $48,856 per acre. While recent public and private transactions have valued Permian land at $40,000 to $45,000 per acre, particularly in the Delaware, analysts have called these valuations a bubble, often noting land prices in the Permian have increased roughly eightfold over the past two years. The management teams of Permian producers now routinely show presentations with slides detailing the number of likely well sites on their acreage and they sometimes go as far as to discuss transaction valuations on a per-well-site basis. While this sounds like the type of metric that internet bubbles were built upon ( EV to dwell time and EV per eyeball ), we actually agree that more traditional metrics do not capture the true production potential of Permian acreage. Page 21

22 Nationally, a 640 acre section of land can generally support four to eight economically viable wells. Due to the number of stacked zones in the Permian, however, a section of land can support anywhere from twenty to forty wells, a portion of which are two mln barrel EUR wells. In their most recent presentation, Diamondback Energy (FANG) shows on slide six they can drill six wells per section in the Wolfcamp A, another six per section in Wolfcamp B and four additional wells per section in the 2nd and 3rd Bone Spring zones or Lower Spraberry - for a total of twenty wells per section. This leaves out potential wells in the relatively-untested Wolfcamp C and D/Cline. Several operators discuss the potential for seven to eight viable development targets (i.e. zones) in the Permian, ultimately resulting in thirty to forty well sites per section. Across all acreage held by public U.S. E&Ps, landowners report average spacing of 464 acres per well, or 1.4 wells per section. This is a misleading statistic as low crude oil prices have rendered drilling in many regions uneconomic and thus no identified well sites are present. Most commonly, companies report (or we calculate) one identified well site for every 80 to 640 acres, or one to eight wells per section: Twenty-four of the thirtyseven U.S. E&Ps we examined (64.9%) fall into this range. The table on the following page shows, among other valuation criteria, the number of company-identified well locations, the implied spacing of their identified well locations and the EV per identified well location. The bottom row of the table shows that the average U.S. E&P has an EV of $2.89 mln per well site and the twenty four companies reporting an average of one identified well site per 80 to 640 acres have an average EV of $2.03 mln per well site. In the Permian, however, five companies report (or we calculate) less than 80 acre well spacing (LPI, FANG, CPE, CXO and RSPP), with these five averaging 40 acres per identified well site, or sixteen wells per section. Despite the relatively low production costs and high EURs for typical Permian wells, the EV per identified well site for these five companies averages $1.81 mln ($2.57 mln for all eight Permian producers) - below the average of $2.17 mln for the twenty-nine non-permian producers. On an EV per identified well site basis, Permian producers are arguably modestly inexpensive companies and well density is still increasing! Introducing our E&P Baskets for 2017 We believe there are several investible U.S. E&P themes for 2017: A handful of companies have significant bankruptcy risk, oily producers should outperform gassy producers, Permian producers will continue to disproportionately benefit from higher proppant intensities and companies currently trading at relatively low valuations per identified well site should outperform. To capitalize on these themes were are introducing a new short candidate basket - the Floundering Four - and a basket of expected relative outperformers - the Favorable Four. We also introduce a simple hedging strategy to eliminate (and profit from) the natural gas exposures of the Favorable Four, which we call the UNGassed strategy. The Floundering Four The Floundering Four (which we were tempted to call the fucked four - but will reserve this status for meetings) are a group of four intermediate-term (twelve to twenty-four month) bankruptcy candidates. We began with a list of eight companies (MCF, SM, SN, XCO, BBG, EPE, WLL, and BCEI) with annual financing needs in excess of 25% of their market cap, assuming stable production volumes and a $60.00/$2.60 WTI crude oil and HH natural gas price environment. While we would normally add additional criteria such as Net Debt:EBITDA in excess of 4.00X or Altman s Z-scores below 1.00, all eight companies (and many others in this report) exceeded these and other reasonable screening criteria for short candidates. Page 22

23 Hold Down [Shift] and [CTRL] and + to Rotate the Page Page 23 Q % 10.40% $288,335 $79,128 $12,505 $354,958 29% 5, % $55, % 2.82 $14.42 NA NA NA 8,254 $3, Yellow = Permian Producers Cabot Oil & Gas Corp COG $ % 3.3% $12,001 $1,539 $517 $13,022 12% % $46, % $9.54 4,750 $ ,725 $7, Range Resources Corp RRC $ % 9.5% $9,577 $2,567 $0 $12,143 21% % $51, % 7.92 $7.37 4,403 $ ,409 $8, Antero Resources Corp AR $ % 5.4% $8,279 $4,244 $28 $12,494 34% % $42, % 5.17 $5.67 4,344 $ $16, SouthWestern Energy Co SWN $ % 12.6% $8,554 $5,768 $998 $13,324 43% % $32, % 5.59 $ ,750 $ ,387 6,587 $2, Rex Energy Corp REXX $ % 8.0% $217 $779 $3 $992 79% % $29, % 6.33 $8.75 1,110 $ $2, Gulfport Energy Corp GPOR $ % 5.1% $3,542 $957 $396 $4,102 23% % $37, % 5.95 $ $ $15, Eclipse Resources Corp ECR $ % 4.6% $857 $491 $114 $1,234 40% % $31, % 5.48 $ $ $4, Unweighted Average 30.8% 12.3% Production-Weighted Average 34% 32.3% $67, % 6.54 $18.35 $ ,048 $8, Total $274,158 $93,569 $12,165 $355,562 5, ,026 Natural Gas Producers Newfield Exploration NFX $ % 4.1% $8,631 $2,430 $165 $10,896 22% % $65, % 6.53 $ ,522 $ ,254 $4, Contango Oil & Gas MCF $ % 0.9% $252 $115 $0 $367 31% % $29, % 4.49 $ $ , $ Laredo Petroleum LPI $ % 11.2% $3,098 $1,392 $19 $4,470 31% % $93, % 6.07 $ ,500 $ $24, Carrizo Oil & Gas, Inc CRZO $ % 19.5% $2,396 $1,298 $2 $3,691 35% % $88, % 6.87 $ ,905 $ $6, SM Energy SM $ % 15.4% $3,351 $2,603 $0 $5,954 44% % $37, % 4.90 $ ,200 $ ,469 1,763 $3, Diamondback Energy FANG $ % 6.1% $7,533 $496 $219 $7,810 6% % $211, % $ ,311 $ $90, Sanchez Energy Corp SN $ % 19.1% $851 $1,747 $324 $2,274 77% % $40, % 3.93 $ ,000 $ $7, Pioneer Natural Resources CoPXD $ % 3.8% $31,488 $3,664 $3,298 $31,854 12% % $136, % $ ,000 $ ,250 $14, Parsley Energy PE $ % 9.2% $6,921 $744 $441 $7,224 10% % $202, % $ ,178 $ $50, EXCO Resources, Inc XCO $ % 11.7% $303 $1,324 $28 $1,599 83% % $32, % 6.15 $ ,963 $ $1, Continental Resources CLR $ % 24.3% $19,462 $7,118 $17 $26,563 27% % $121, % $ ,000 $ ,750 $7, Energen Corp EGN $ % 4.1% $5,603 $551 $310 $5,844 9% % $91, % 9.91 $ ,500 $ $9, Matador Resources Co MTDR $ % 16.6% $2,271 $392 $0 $2,663 15% % $95, % 9.32 $ ,804 $ $8, Callon Petroleum CPE $ % 12.5% $2,546 $329 $0 $2,874 11% % $213, % $ ,076 $ $125, PDC Energy, Inc PDCE $ % 7.2% $3,693 $495 $109 $4,079 12% % $71, % 6.86 $ $ $23, Concho Resources CXO $ % 5.0% $19,337 $3,332 $481 $22,188 15% % $152, % $ ,000 $ ,012 $21, RSP Permian Inc RSPP $ % 10.5% $3,942 $687 $33 $4,596 15% % $174, % $ ,370 $ $47, Denbury Resources Inc DNR $ % 18.8% $1,287 $3,082 $3 $4,366 71% % $67, % 4.32 $ ,545 $ ,134 $3, Cimarex Energy Co XEC $ % 2.5% $12,763 $1,487 $642 $13,609 11% % $83, % $ ,000 $ ,692 $1, Resolute Energy Corp REN $ % 18.3% $402 $547 $0 $948 58% % $79, % 3.89 $ $ $23, EOG Resources, Inc EOG $ % 1.7% $53,253 $6,986 $780 $59,459 12% % $107, % 8.26 $ ,000 $ ,782 $10, Bill Barrett Crop BBG $ % 9.5% $335 $712 $87 $959 74% % $54, % 3.50 $ ,000 $ $1, WPX Energy Inc WPX $ % 11.2% $4,892 $2,732 $1,031 $6,593 41% % $77, % 5.54 $ ,975 $ ,184 $5, Devon Energy DVN $ % 2.6% $23,096 $12,707 $1,723 $34,080 37% % $52, % 3.39 $ ,300 $ ,104 $3, EP Energy Corp EPE $ % 42.8% $1,106 $3,929 $39 $4,996 79% % $59, % 3.90 $9.15 5,519 $ ,042 $4, Ring Energy Inc REI $ % 8.1% $459 $0 $8 $451 0% % $210, % $ $ $6, Whiting Petroleum Corp WLL $ % 18.4% $2,407 $4,691 $15 $7,083 66% % $52, % 4.96 $ ,704 $ ,952 $3, Clayton Williams Energy CWEI $ % 53.1% $1,471 $930 $158 $2,243 41% % $165, % $ ,934 $ $2, Chesapeake Energy Corp CHK $ % 15.1% $7,934 $9,649 $4 $17,579 55% % $26, % 2.15 $ ,385 $ ,442 $1, Bonanza Creek Energy BCEI $ % 23.0% $51 $1,055 $170 $ % % $40, % 4.62 $9.23 3,200 $ $7, Company Ticker Oil Crude and Gas Oil Producers Producers Share Price Short Gross 3 Month % Interest % Market Cap Debt Change Float (mln) (mln) EV:Cons Enterprise EV per TTM Revenue Cash Value Net MBOE/Day Production Flowing Production Current (mln) (mln) Debt:EV Production Mix Oil % BOE EV:EBITDA Growth Year EV:BBL Total Reserves Company Identified Well Locations EV:Identified Well Location (mln) Well Spacing (Acres per Location) Total Acreage (x1,000) Hold Down [Shift] and [CTRL] and + to Rotate the Page EV per Acre Acres per Share Equity Metrics Enterprise Value Valuation Metrics

24 We then excluded EXCO Resources (XCO) and Bonanza Creek (BCEI) from our Floundering basket due to their lack of trading liquidity and low share prices (shorting ~$1.00 shares is risky at best), despite their imminent bankruptcy risks We also excluded Contango Oil and Gas (MCF) and SM Energy (SM) as both are working very hard to buy their way into the Permian while they still have the financial flexibility to do so: In July, Contango Oil and Gas closed the purchase of 4,900 net undeveloped acres in the Delaware basin for $10 mln upfront, plus a $10 mln drilling commitment and $5 mln of contingent payments. SM Energy announced in August they were selling their waterflood assets in New Mexico and acreage in North Dakota and Montana for a total of $173 mln (79,000 acres, 3,300 BOE/d). A week later, SM announced the acquisition of 24,783 acres (4,900 BOE/d) in Howard County in the Midland Basis for $980 mln. In October, SM announced the purchase of 35,700 net acres (2,400 BOE/d) in Howard and Martin counties from Qstar LLC for roughly $1,460 mln while selling 55,000 non-core Williston acres for $710 mln to Oasis Petroleum. Given the transformative nature of these transactions, we excluded MCF and SM from our likely bankruptcy candidates, although risks certainly remain as both companies try to grow into their overhead. This leaves the Floundering Four - Sanchez Energy (SN), Bill Barrett Corp (BBG), EP Energy Corp (EPE) and Whiting Petroleum (WLL). Some basic metrics for the four companies are shown on the following page. Sanchez Energy (SN) has an $851 mln market cap (including a $269 mln preferred), $1,747 mln of gross debt and $324 mln of cash - resulting in an EV of $2,274 mln. They produce approximately 52,000 BOE/d, 32.1% of which is classified as crude oil, primarily from 200,000 net acres in the Eagle Ford. Sanchez has hedged approximately 39% of expected 2017 crude oil production, half with a $45.00/Bbl floor and half with roughly $51.00/Bbl swaps, and 94% of expected 2017 natural gas production at $3.02/Mmbtu. Unhedged second quarter price realizations were $24.80/BOE. Sanchez has a tremendous overhead problem, with $24 mln of quarterly SG&A and $32 mln of quarterly interest expense, resulting in overhead of $10.97 per BOE ($1.83/Mmbtu). Despite slides to the contrary, Sanchez Energy also had LOE of $10.05 per BOE ($1.68/MMBtu), making them a very uncompetitive gas producer. Finally, despite declining production, Sanchez plans to spend $250 to $300 mln on upstream CapEx in 2016 ($15.07/BOE or $2.51/MMBtu at the midpoint). We estimate that maintenance CapEx is $18.63/BOE ($3.11/MMBtu). Bill Barrett Corp (BBG) has a market cap of $355 mln, $712 mln of gross debt and $87 mln of cash - resulting in an EV of $959 mln. They produce approximately 17,000 BOE/d, 63.7% of which is classified as crude oil, primarily from the Wattenberg/Denver-Julesburg (DJ) Basin in Wyoming and Colorado, and hold 572,000 total acres. Bill Barret is benefitting tremendously from their hedge program, with 70% of remaining 2016 crude oil production hedged at $72.57/Bbl and 26% of natural gas production hedged at $4.10/MMBtu. In 2017, roughly 35% of expected crude oil production is hedged at an average of $61.70/Bbl and roughly 50% of expected natural gas production is hedged at $2.96/MMBtu. Due to their strong hedge book, Bill Barret realized $45.06/BOE in the recently-released third quarter, while revenue excluding hedges was $32.02/BOE. While Bill Barrett enjoys slightly below average LOEs of $7.85/BOE ($8.42/BOE is average), they suffer from incredibly high overhead: SG&A and interest expense total $15.78/BOE - or 49.3% of unhedged revenue ($5.32/BOE overhead is average). Bill Barrett is guiding 2016 CapEx to a range of $75 - $100 mln, but their production is in rapid decline and we calculate maintenance CapEx is $218 mln - or $35.01/BOE. Adding LOE, overhead and maintenance CapEx, we find total costs are $58.64/BOE, nearly double current unhedged realizations! Page 24

25 The Floundering Four Basic Metrics Enterprise Value Revenue, Production Mix and EBITDA Share Price Market Cap (mln) Gross Debt (mln) Cash (mln) Enterprise Value (mln) Net Debt:EV TTM Revenue (mln) Q2 16 Annualized EBITDA Net Debt: Revenue Net Debt: EBITDA Production Mix Oil % Company Ticker Oil and Gas Producers Sanchez Energy Corp SN $8.84 $851 $1,747 $324 $2,274 77% $588 $ % Bill Barrett Corp BBG $5.56 $335 $712 $87 $959 74% $328 $ % EP Energy Corp EPE $4.38 $1,106 $3,929 $39 $4,996 79% $1,812 $1, % Whiting Petroleum Corp WLL $8.74 $2,407 $4,691 $15 $7,083 66% $1,549 $ % Actual Q2 16 Revenue per BOE $45.64/$2.25 Reported Lifting Costs per BOE Reported Finding Costs per BOE Reported Production Taxes Per BOE Reported SG&A per BOE The 'Unit Economics' Total Reported Reported Interest Income Expense Statement per BOE Expenses Overhead (SG&A + Interest Expense) per BOE TTM Capex per BOE TTM Production Growth Estimated Maintenance CapEx per BOE Company Ticker Oil and Gas Producers Sanchez Energy Corp SN $24.80 $10.05 $0.87 $1.22 $4.71 $6.26 $23.10 $ $ % -$18.63 Bill Barrett Corp BBG $31.02 $7.85 $0.04 $2.19 $6.18 $9.60 $25.86 $ $ % -$35.01 EP Energy Corp EPE $30.99 $8.45 $0.38 $1.82 $4.16 $9.49 $24.31 $ $ % -$80.38 Whiting Petroleum Corp WLL $35.11 $10.80 $1.02 $2.20 $2.74 $6.44 $23.19 $9.18 -$ % -$56.76 Bloomberg, Company Filings and Presentations, Unit Economics Calculations Estimated FCF Breakeven WTI Price at $2.60 HH Financing Requirements Financing Needs as a % of Current Mkt Cap 2017 Financing Needs, Maint CapEx and $60.00/$2.60 Corp Bond Yield to Maturity Altman Z- Score (<1.81 = Distressed) Company Ticker Oil and Gas Producers Sanchez Energy Corp SN $49.04 $ % 11.13% Bill Barrett Corp BBG $60.89 $ % 15.68% EP Energy Corp EPE $69.12 $1, % Whiting Petroleum Corp WLL $70.04 $1, % 8.63% Page 25

26 EP Energy Corp (EPE) has a market cap of $1,106 mln, $3,796 mln of gross debt and $39 mln of cash - resulting in an EV of $4,996 mln. They produce 79,000 BOE/d, 53.4% of which is classified as crude oil, from approximately one million total acres. Roughly half of current production comes from the Eagle Ford, with the remainder split between the Wolfcamp and Altamont. That said, EP Energy is spending nearly 60% of incremental CapEx in the Wolfcamp in an attempt to lower production costs. Like the other Floundering companies, EP Energy is benefitting tremendously from their derivatives program, with just over 90% of remaining 2016 oil production hedged at $80.77/Bbl. Not surprisingly, EP has realized $514 mln of derivative gains in 2016 through the third quarter - equal to 41% of their forecasted 2016 revenue ($1,246 mln). Looking forward, 75% of estimated 2017 crude oil production is hedged with a floor of $62.34/Bbl and 55% of estimated natural gas production is swapped at $3.25/MMBtu. EP Energy realizes quite average LOEs of $8.45/BOE ($8.42/ BOE is average), but like the other Floundering companies suffers from high overhead: SG&A and interest expense total $13.65/BOE - or 44.6% of unhedged revenue ($5.32/BOE is average). Despite plunging production volumes, EP Energy has guided 2016 capital spending to a range of $475 to $505 mln, or $15.89/BOE. We calculate that maintenance CapEx is $80.38/BOE, which seems quite high until you consider production is declining by 22% YOY with current spending. Going forward, a new focus on their Wolfcamp assets should keep maintenance CapEx closer to $35.00 per BOE, but keep in mind LOE + overhead is $22.10/BOE and EP Energy realized $30.99/BOE in the second quarter, prior to derivative gains. Whiting Petroleum (WLL) has a market cap of $2,407 mln, $4,086 mln of gross debt and $15 mln of cash - resulting in an EV of $7,083 mln. They produce 120,000 BOE/d, 71.2% of which is classified as crude oil, from a total of nearly two million acres. Almost all (88%) of their production comes from the Bakken, with the remainder largely coming from the Niobrara. Whiting suffers from painful differentials, most recently guiding crude oil price realization differentials (to NYMEX) of $8.50/Bbl and natural gas differentials (again to NY- MEX) of $1.05/Mmbtu. Whiting has 68% of remaining 2016 crude oil production hedged with a floor of $53.75/Bbl and 49% of expected 2017 crude oil production hedged with a floor of $44.47/Bbl to $53.00/Bbl and a ceiling of $60.06/Bbl to $70.44/Bbl. Whiting suffers from high LOEs of $10.80/BOE ($8.42/BOE average), as well as high overhead: SG&A plus interest expense totals $9.18/BOE ($5.32/BOE average). Whiting is on track for 2016 capital expenditures to total $500 mln, or $10.59/BOE, but we note production is expected to plunge from 155,200 BOE/d in Q to 115,000 BOE/d in the fourth quarter of 2016 with only 10,200 BOE/ d of production having been divested in the interim. We calculate Whiting suffers maintenance CapEx of $56.76/BOE. Adding LOE, overhead and maintenance CapEx we find Whiting s total costs are $58.64/BOE, nearly double unhedged realizations ($32.34/BOE). The Favorable Four While U.S. E&Ps generally have distressed balance sheets and could very likely see price realizations fall in 2017 as a move to $65.00/Bbl WTI crude is more than offset by a decline in HH gas to $2.00/MMBtu, we understand some clients have a mandate that necessitates owning oil and gas producers. As we did in late 2014, we have created a basket of oil and gas producers which we believe have very little bankruptcy risk and should outperform the sector (defined by us as the Energy Select Sector - represented by the XLE). We began our search for the Favorable Four by examining the potential cash generation and financing needs over the coming twelve months: We believe there are four companies which would generate small amounts of FCF in our $60.00/$2.60 scenario (PXD, CPE, PDCE and WPX) and an additional ten companies that would need to raise less than 5.00% of their current EVs over the coming twelve months (NFX, LPI, CRZO, FANG, PE, CLR, RSPP, DNR, EOG and REI). Page 26

27 We then excluded the companies with high overhead - which we define as SG&A plus interest expense in excess of $10.00/BOE - keeping in mind that average realizations for the group were $33.12 per BOE in the second quarter (62.7% average oil production mix, $45.64 WTI crude and $2.25/MMBtu HH gas). This removed LPI, CRZO, DNR, WPX and REI from our potential Favorable list. Our next criteria was to exclude companies with Altman Z-scores less than 1.00, a key criteria for bankruptcy risk over the past two years (ironically Z-scores are said to predict two year bankruptcy risk). This removed NFX, CLR and CPE from our list. Our final criteria was to exclude companies with less than 50% of their production being reported as crude oil. This removed PDCE and EOG, leaving us with FANG, PXD, PE and RSPP. A table showing the basic metrics of the Favorable Four is shown on the following page. Diamondback Energy (FANG) has a $7,533 mln market cap, $496 mln of gross debt and $219 mln of cash - resulting in an EV of $7,810 mln. They produce 37,000 BOE/d, 72.2% of which is classified as crude oil, entirely from 105,000 net acres held in the Permian (19,000 Delaware acres). Diamondback has hedged approximately 45% of anticipated 1H 2017 crude oil production (2H 2017 largely unhedged) using collars with roughly $54.00/Bbl ceilings and $45.00/Bbl floors. Approximately 20% of anticipated 2017 natural gas production is swapped at $3.14/MMBtu to $3.30/MMBtu. Diamondback has roughly average LOEs of $8.00/BOE ($8.42/ BOE average) and average overhead - SG&A plus interest expenses totals $5.83/BOE ($5.32/BOE average). According to our calculations, Diamondback spends $28.29/BOE on maintenance CapEx, resulting in a total estimated FCF breakeven WTI crude oil price (at $2.60/MMBtu HH gas) of $46.92/Bbl. Pioneer Natural Resources (PXD) has a market cap of $31,488 mln, $3,664 mln of gross debt and $3,298 mln of cash - resulting in an EV of $31,854 mln. They produce roughly 230,000 BOE/d, 57.9% of which is classified as crude oil, primarily from a whopping 800,000 gross acres in the Permian. Pioneer has hedged approximately 75% of anticipated 2017 crude oil production using collars with roughly $50.00/Bbl floors and $65.00/Bbl ceilings and 55% of natural gas production using collars with $2.91/MMBtu floors and $3.49/MMBtu ceilings. As has become fashionable of late, Pioneer has written $2.43/MMBtu natural gas puts covering 55% of expected 2017 production as well - a decision they may regret in the second half of the year. Pioneer has roughly average LOEs of $8.36/BOE ($8.42/BOE average) and slightly above average overhead - SG&A plus interest expenses totals $6.42/BOE ($5.32/BOE average). According to our calculations, Pioneer spends $17.61/BOE on maintenance CapEx, resulting in a total estimated FCF breakeven WTI crude oil price (at $2.60/MMBtu HH gas) of $49.63/Bb - higher than Diamondback despite lower costs due to a 57.9% crude oil production mix (natural gas costs less to produce and the production mix reduces overall realizations per BOE). Parsley Energy (PE) has a market cap of $6,921 mln, $744 mln of gross debt and $441 mln of cash - resulting in an EV of $7,224 mln. They produce 43,000 bpd, 66.4% of which is classified as crude oil, from 143,000 gross acres in the Permian (43,000 Delaware acres). Parsley has hedged approximately 65% of anticipated 2017 crude oil production with put spreads, buying $45.00/Bbl to $53.00/Bbl puts and writing $34.00/Bbl to $41.00/ Bbl puts. Parsley enjoys low LOEs of $6.34/BOE ($8.42/BOE average) but relatively high overhead - SG&A plus interest expenses totals $9.18/BOE ($5.32/BOE average). According to our calculations, Parley Energy spends $28.88/BOE on maintenance CapEx, resulting in a total estimated FCF breakeven WTI crude oil price (at $2.60/MMBtu HH gas) of $50.13/Bbl. Page 27

28 The Favorable Four Basic Metrics Enterprise Value Revenue, Production Mix and EBITDA Share Price Market Cap (mln) Gross Debt (mln) Cash (mln) Enterprise Value (mln) Net Debt:EV TTM Revenue (mln) Q2 16 Annualized EBITDA Net Debt: Revenue Net Debt: EBITDA Production Mix Oil % Company Ticker Oil and Gas Producers Diamondback Energy FANG $96.54 $7,533 $496 $219 $7,810 6% $507 $ % Pioneer Natural Resources Co PXD $ $31,488 $3,664 $3,298 $31,854 12% $4,200 $1, % Parsley Energy PE $33.51 $6,921 $744 $441 $7,224 10% $356 $ % RSP Permian Inc RSPP $38.78 $3,942 $687 $33 $4,596 15% $338 $ % Actual Q2 16 Revenue per BOE $45.64/$2.25 Reported Lifting Costs per BOE Reported Finding Costs per BOE Reported Production Taxes Per BOE Reported SG&A per BOE The 'Unit Economics' Total Reported Reported Interest Income Expense Statement per BOE Expenses Overhead (SG&A + Interest Expense) per BOE TTM Capex per BOE TTM Production Growth Enterprise Value (mln) Company Ticker Oil and Gas Producers Diamondback Energy FANG $36.98 $8.00 $4.58 $2.43 $2.84 $2.99 $20.85 $5.83 -$ % $7,810 Pioneer Natural Resources Co PXD $29.24 $8.36 $9.56 $1.70 $3.78 $2.64 $26.04 $6.42 -$ % $31,854 Parsley Energy PE $33.13 $6.34 $0.00 $1.97 $5.33 $3.85 $17.49 $5.83 -$ % $7,224 RSP Permian Inc RSPP $36.97 $13.66 $0.00 $2.06 $2.58 $5.39 $23.69 $7.97 -$ % $4,596 Bloomberg, Company Filings and Presentations, Unit Economics Calculations Estimated FCF Breakeven WTI Price at $2.60 HH Financing Requirements Financing Needs as a % of Current Mkt Cap 2017 Financing Needs, Maint CapEx and $60.00/$2.60 Corp Bond Yield to Maturity Altman Z- Score (<1.81 = Distressed) Company Ticker Oil and Gas Producers Diamondback Energy FANG $46.92 $89 1.2% 6.27% 3.43 Pioneer Natural Resources Co PXD $49.63 $0 0.0% 2.37% 2.92 Parsley Energy PE $50.13 $ % RSP Permian Inc RSPP $58.45 $ % 5.64% 1.57 Page 28

29 RSP Permian Inc (RSPP) has a market cap of $3,942 mln, $687 mln of gross debt and $33 mln of cash - resulting in an EV of $4,596 mln. They produce 29,800 bpd, 73.2% of which is crude oil, from 101,700 acres in the Permian (41,000 Delaware). RSP has hedged approximately 52% of anticipated 2017 crude oil production using collars with roughly $45.00/Bbl floors and $54.00/Bbl to $60.00/Bbl ceilings. RSP has low normalized LOEs of $6.40/BOE ($8.42/BOE average) and moderately high overhead - SG&A plus interest expenses total $7.97/BOE ($5.32/BOE average). According to our calculations, RSP spends $42.79/BOE on maintenance CapEx, resulting in a total estimated FCF breakeven WTI crude oil price (at $2.60/MMBtu HH gas) of $58.45/Bbl. Parsley is currently growing production by roughly 60+% annually, inflating their capital expenditures even on a per-boe basis, hence the lower FCF breakeven price that the historical data would suggest. The Performance of the Floundering Four and Favorable Four So far in 2016, the equally-weighted Floundering Four stock basket has rallied 55.77% while the equallyweighted Favorable Four basket has increased 72.25%, as the following graphic displays: Basket Performance YTD of Floundering Four and Favorable Four Bloomberg Although the performance of the two baskets so far in 2016 has been relatively close, we should point out that since last Friday, the Favorable Four basket has rallied 5.54% while the Floundering Four rallied 15.30%: The OPEC-fueled E&P rally this week wreaks of short-covering. We believe the rally provides a very good entry point to short overvalued E&Ps and, as we wrote in our Articles of the Week this morning, our calcualtions show OPEC did not actually cut production - they instead guided production will follow normal seasonality in the first half of 2017! Page 29

30 The UNGassed Basket While we don t think the timing is right just yet, we will be pounding the table very hard in coming weeks on what we believe is the best risk/reward trade of 2017: Shorting natural gas. Our views will be supported by a 30+ page Natural Gas Outlook report and a Guide to Flawed Natural Gas ETFs. Our main hesitation today is that there is a real risk that cold weather and a fairly tight U.S. natural gas supply/demand situation could send HH gas prices over $4.00/MMBtu for a short while this winter, causing 30%+ losses for those short natural gas ETFs. We also believe there is little benefit to trying to pick the exact top for natural gas prices: Assuming HH gas falls to $2.00/MMBtu next fall as we believe it will, shorting the UNG (for example) with HH gas at $3.40 would yield a 61% return assuming contango totals 35% over the coming year (ie the UNG underperforms front-month futures by 35%). Putting the UNG short on with HH gas at $2.80/ MMBtu still yields a 53% return in the same scenario. What we can recommend today is to short the UNG against our Favorable Four names to effectively cancel out their natural gas exposure (32.58% of production). This strategy creates a synthetic crude oil pure-play and allows investors to profit from the underperformance of the UNG shares relative to front-month natural gas (43.2% YTD as-of this morning). While our Floundering Four and Favorable Four baskets are merely equally weighted (not market cap weighted) baskets, we will take a moment to specify the calculation for our UNGassed basket. The $1,000 basket will own $250 of each of the Favorable Four companies ( shares of FANG, shares of PXD, shares of PE and shares of RSPP) and then short $ worth of UNG shares ( ) on margin, creating a $1,000 basket. This calculation is inline with common pairs trading performance calculations where the total return is allocated over the value of the long positions in the pair. [Blame our lawyers for making you suffer that paragraph!] We strongly believe that hedging the natural gas exposure of any U.S. E&P in 2017 will prove to be a very good strategy and urge clients to refer to page six of this report to view the natural gas and NGL exposures of the E&Ps analyzed in this report (the production mix column is included on the slide on page twenty three as well). Enter the Matrix (or Matrices) We at Unit Economics love a good Matrix. To graphically show the significance of natural gas prices on the cash flows of the various E&Ps discussed in this report we have taken our love of matrices to a whole new level: Starting on page thirty seven, we have included an estimated FCF per BOE matrix for each of the thirty-seven E&Ps covered in this report. The FCF calculations are based on the current production mix, overhead and cost structures of each company and assume sufficient capital spending to maintain current production. The area of each matrix shaded in red signifies negative FCF while the green areas signify positive FCF. Conclusions In short, we see a lot of opportunity for investors in 2017 who are aware of the impact of natural gas prices on U.S. E&P realizations. Even better, those that get their natural gas price forecasts right and creatively hedge their portfolios to reflect these views have an opportunity to meaningfully outperform. We greatly look forward to releasing our Natural Gas Outlook report in coming weeks to assist in this effort! Page 30

31 Appendix A: U.S. E&P Presentation Slides of Interest Apache: Well Cost Reductions of 45% Denbury: Cash Cost Reductions 25% Since 2014 Page 31

32 Denbury: Select U.S. E&P Price Realizations in Q2 Averaged $26.56/BOE NFX: Drilling Days in STACK Down from 39 in 2012 to 14 in 2016, Best Wells at 8 Page 32

33 Vermillion Energy: Capital Intensity per BOE/d Sanchez Energy: Cost Reductions Behind Us? Page 33

34 ENERCOM Consulting: Gross Funding Totals for North American E&Ps Page 34

35 Appendix B: Oil Sector Bankruptcies Provided by Haynes and Boone, LLP 2015 Page 35

36 Appendix B: Oil Sector Bankruptcies Provided by Haynes and Boone, LLP 2016 Page 36