U.S. Independent E&Ps

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1 Americas/United States Equity Research Oil & Gas Exploration & Production Research Analysts Mark Lear, CFA Edward Westlake Venkatesh Duvvuri Tom Hughes Veronica Liu Ben Combes, CFA Chandra Meenaga U.S. Independent E&Ps WEEKLY ANALYSIS Weekly Upstream Monitor Beta On. The XOP was up 6% this week fueled by constructive comments out of OPEC and the inevitability of Winter driving appetite for oil beta (with the Bakken outperforming the Permian) and for gas equity. This week we got the first long term update from NBL in three years, and while US onshore oil growth was better than we expected, it gave back all its outperformance vs the XOP over the past month and then some, with some investors raising inventory concerns. We spent a couple of days with EGN management this week in NYC, and expect an increasing investor focus on the stock ahead of a growth inflection point starting in 2017, which we do not think is being properly reflected in the valuation. 3Q Production and Capex Revisions. We exit 3Q16 earnings with corporates providing a more constructive view on longer term oil and gas fundamentals despite the uncertainty surrounding upcoming OPEC deliberations. In terms of headline numbers specific to the quarter, we note that overall volumes were largely in-line to slightly ahead, coming in ~1.7% above consensus expectations, while volumetrically the beats were mainly driven by NGL and gas as oil production came in 1.0% above ours and 0.7% above consensus expectations, while gas volumes were a 1.4% beat relative to our estimates and 1.0% above consensus, and finally NGLs came in 5.9% above our estimates and 4.7% above consensus. Accounting for volumes associated with recent asset sales, our 2016 and 2017 production estimates remain largely unchanged, but given the lagged response time between activity picking up and production coming online, forecasted outspends have widened, especially in In 2016 at the strip, we expect our coverage universe to outspend cash flow by 19%, and by 15% in Wells of the Week A Closer Look at the Northern Powder River Basin Hotspot. Following our review of the Southern PRB Hotspot (Link: Wells of the Week Looking Into CHK's LT Oil Growth Driver), we wanted to take a closer look at the northern PRB hotspot, located near the Campbell Converse county line, as this play has been increasingly discussed by public operators such as EOG and DVN during 3Q earnings. DISCLOSURE APPENDIX AT THE BACK OF THIS REPORT CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, LEGAL ENTITY DISCLOSURE AND THE STATUS OF NON-US ANALYSTS. US Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.

2 Table of contents Equity Performance: E&P Rally Continues 6 Weekly Topics 9 3Q16 Earnings Review... 9 NBL US Onshore Long-Term Outlook Update Wells of the Week A Closer Look at the Northern Powder River Basin Hotspot 26 Valuation Snapshot 34 Implied Oil and Gas Prices Hedging Oil Gas Oil and NGL Macro Gas Macro Focus on Capex and Costs Appendix: Other Useful Statistics Rig Count U.S. Independent E&Ps 2

3 Table of Exhibits Figure 1: Equity Performance by Basin - Week up to 11/17/ Figure 2: Equity Performance by Market Capitalization CS E&P Universe Week up to 11/17/ Figure 3: Equity Performance YTD... 7 Figure 4: Equity Performance Week up to 11/17/ Figure 5: Short Interest (As of Last Settlement Date 11/09/16)... 8 Figure 6: 3Q16 Production Estimates - Actuals vs Estimates Figure 7: 3Q16 Oil Production Estimates - Actuals vs Estimates Figure 8: 3Q16 Gas Production Estimates - Actuals vs Estimates Figure 9: 3Q16 US Gas Production - Actuals vs Estimates Figure 10: 3Q16 NGL Production Estimates - Actuals vs Estimates Figure 11: CS Production Volume Estimate Changes (Mboe/d) Figure 12: CS US Oil Production Estimate Changes (Mbbl/d) Figure 13: CS US Gas Production Volume Estimate Changes (Mmcf/d) Figure 14: CS Capex Estimate Changes ($MM) Figure 15: CS Cash Flow Estimate Changes at the CS Deck ($MM) Figure 16: 2016 & 2017 Outspends at the Strip Figure 17: 3rd Bone Spring Production and Cume Figure 18: CXO 3Q16 3rd Bone Spring Results Figure 19: NBL Delaware Completions and CXO 3 rd Bone Spring Locations Figure 20: NBL Delaware Basin Type Curves (7,500 ft lateral) Figure 21: NBL vs. ROSE Well Result Evolution and Completion Design Figure 22: NBL vs. ROSE Well Performance Figure 23: NBL DJ Well Design Evolution and Production Results Figure 24: NBL East Pony Well Results by Vintage Figure 25: NBL Wells Ranch Well Results by Vintage Figure 26: DJ and PRB Hotspots Figure 27: Drillable Formations in the PRB Figure 28: IRR by Drilling Zones Figure 29: Historic Turner by Peak Oil (2013+) Figure 30: Significant GOR Shift Seen within A Few Miles Figure 31: Historical Turner Wells with Oil Cut Below 40% Figure 32: Historical Turner Wells with Oil Cut Between 40% and 60% Figure 33: Historical Turner Wells with Oil Cut Between 60% and 80% Figure 34: Historical Turner Wells with Oil Cut Above 80% Figure 35: DJ GOR Map Figure 36: Southern PRB Hotspot GOR Map U.S. Independent E&Ps 3

4 Figure 37: GOR Shift Over Life of Well for Turner Wells Figure 38: Turner Type Curves Figure 39: Estimated Heat Map Based on Historical Wells Figure 40: Modeled EOG PRB Type Curve Figure 41: PRB Wells Historical Cume Production Figure 42: Outperforming PRB Wells Figure 43: Sweet Spot of Northern Hotspot Acreage Figure 44: EOG PRB Acreage Post Yates Acquisition Figure 45: Vintage Type Curve By Year Figure 46: Equity Implied Gas Prices As of 11/18/ Figure 47: Equity Implied Oil Prices As of 11/18/ Figure 48: E&P Upside/Downside to NAV Figure 49: E&P Upside/Downside to NAV at CS Deck and Strip Figure 50: 2016 EV to EBITDA (unhedged at the strip, $45.57/bbl WTI, $2.76/MMbtu) Figure 51: 2016 EV to EBITDA (hedged at the CS Deck, $42.18/bbl WTI, $2.45/MMbtu gas) Figure 52: 2017 EV to EBITDA (unhedged at the strip, $48.69/bbl WTI, $3.00/MMbtu) Figure 53: 2017 EV to EBITDA (hedged at the CS Deck, $55.00/bbl WTI, $3.25/MMbtu gas) Figure 54: 2018 EV to EBITDA (unhedged at the strip, $50.83/bbl WTI, $2.94/MMbtu) Figure 55: 2018 EV to EBITDA (hedged at the CS Deck, $62.50/bbl WTI, $3.50/MMbtu gas) Figure 56: Debt Adjusted Cash Flow Per Share ( E) Figure 57: 2016 Net Debt to EBITDA Figure 58: 2017 Net Debt to EBITDA Figure 59: Net Debt (as a % of EV) Figure 60: 2016 Outspend at the CS Deck ($42.18 WTI/$2.45 NYMEX) Figure 61: 2017 Outspend at the CS Deck ($55.00 WTI/$3.25 NYMEX) Figure 62: 2016 Oil Volumes Hedged Figure 63: 2017 Oil Volumes Hedged Figure 64: 2016 Gas Volumes Hedged Figure 65: 2017 Gas Volumes Hedged Figure 66: Regional Oil Differentials to WTI - As of 11/18/ Figure 67: NGL Composite Prices (at Mt. Belvieu) - As of 11/18/ Figure 68: US Natural Gas Storage - As of 11/11/ U.S. Independent E&Ps 4

5 Figure 69: Select Northeast Gas Price Differential to Henry Hub - As of 11/18/1646 Figure 70: 2016 and 2017 Capex per boe Figure 71: Cash Costs per boe Figure 72: Large Cap Oil Headline Cashflow Cash Margins - Hedged ($/boe, ) Figure 73: SMID Cap Oil Headline Cashflow Cash Margins - Hedged ($/boe, ) Figure 74: Gas Cash Margins ($/Mcfe, ) Figure 75: Historical Lease Operating Expense ($/boe) Figure 76: Texas Well Completions (1 of 3) Week up to 11/18/ Figure 77: Texas Well Completions (2 of 3) Week up to 11/18/ Figure 78: Texas Well Completions (3 of 3) Week up to 11/18/ Figure 79: CS Coverage Comp Sheet (As of 11/18/2016) Figure 80: 2016 and 2017 Revenue per boe Figure 81: 2016 and 2017 EBITDAX per boe Figure 82: 2017 EBITDAX/boe vs. % oil (at Credit Suisse deck) Figure 83: Total Oil Production (Mbbl/d) Figure 84: Oil Growth % Figure 85: E US Onshore Oil Volumes (Mbbl/d) Figure 86: Total Gas Production (MMcf/d) Figure 87: Total NGL Production (bbl/d) Figure 88: E Capex Estimates Figure 89: E Cash Flow Estimates Figure 90: Leading Edge Completion Tracker Figure 91: Total US Rig Count by Basin As of 11/18/ Figure 92: Weekly US Horizontal Rig Count (As of 11/18/2016) Figure 93: US Weekly Natural Gas v. Oil Rig Count Figure 94: US Crude Oil Storage Week of 11/11/ U.S. Independent E&Ps 5

6 -71% -37% -31% -31% -28% -9% -3% -4% -7% -9% -7% -1% 0% 4% 3% 6% 3% 1% 0% 15% 11% 8% 11% 8% 18% 14% 15% 10% 28% 26% -59% -48% -52% -52% -40% -37% -29% -28% -19% -16% -5% -8% -13% -2% -4% -4% -5% -7% -5% -5% -7% -1% 1% 7% 4% 3% 6% 3% 3% 1% 0% 7% 3% 8% 8% 3% 3% 9% 15% 17% 24% 14% 30% 27% 22% 21% 18% 15% 11% 15% 10% 30% 26% 39% 39% 34% 43% 51% 47% 59% 18 November 2016 Equity Performance: E&P Rally Continues Figure 1: Equity Performance by Basin - Week up to 11/17/ YTD Q Q Q QTD 80% 60% 40% 20% 0% -20% -40% -60% -80% Source: Thomson Reuters, Credit Suisse estimates Figure 2: Equity Performance by Market Capitalization CS E&P Universe Week up to 11/17/ YTD Q Q Q QTD 40% 20% 0% -20% -40% -60% -80% Source: Thomson Reuters, Credit Suisse estimates U.S. Independent E&Ps 6

7 -150% -100% -50% 0% 50% 100% 150% 200% 250% 300% -35% -30% -25% -20% -15% -10% -5% 0% 5% 10% 15% 20% 18 November 2016 Figure 3: Equity Performance YTD Figure 4: Equity Performance Week up to 11/17/16 CWEI CNX ECA WPX CLR RICE UPL PE LPI SM CPE BBG OAS RSPP AREX SN DNR ECR FANG SWN XEC CXO PXD RRC APA EGN MUR DVN CHK EOG QEP EQT APC PDCE MRO CRZO COG NFX AR NBL HES JONE OXY GPOR XOG. WLL SYRG EPE COP KOS CRK GST WTI NOG TPLM REXX CIE HK BCEI EXXI EOX SGY WRES -0.5% -2.4% -3.3% -4.2% -4.8% -6.6% -8.5% -10.5% -14.5% -33.8% -54.7% -66.9% -73.2% -76.7% -77.8% -81.0% -87.1% -89.3% -89.4% -96.9% 129.0% 122.2% 120.7% 116.0% 113.3% 100.8% 85.1% 75.6% 72.6% 72.4% 69.5% 63.4% 63.0% 60.9% 58.9% 48.5% 46.7% 46.4% 45.9% 40.7% 40.5% 40.3% 38.3% 38.1% 37.6% 35.0% 34.0% 30.9% 30.4% 29.9% 28.3% 26.5% 23.5% 22.8% 22.6% 22.3% 22.2% 12.8% 7.3% 4.2% 1.3% 0.3% 274.4% EPE JONE AREX HK MUR ECA CLR CHK GST CIE XCO WLL LPI SM BCEI RRC APA HES TPLM BBG SN SWN UPL NFX XOG. RICE RICE WPX DNR CWEI OXY PDCE ECR MRO CPE EGN OAS KOS CXO FANG DVN GPOR PXD EQT CRK QEP COG PE SYRG XEC APC RSPP CNX AR WRES CRZO COP WTI NBL NOG EXXI SGY REXX -28.1% -11.6% -0.4% -0.8% -1.3% -2.2% -2.8% -4.4% 15.2% 13.0% 13.0% 11.4% 10.5% 10.3% 9.3% 8.5% 7.7% 7.7% 7.6% 7.4% 6.9% 6.7% 6.6% 6.4% 6.4% 6.1% 5.9% 5.9% 5.9% 5.4% 5.2% 5.2% 5.1% 5.1% 5.1% 5.1% 4.9% 4.6% 4.4% 4.2% 3.9% 3.8% 3.7% 3.0% 3.0% 2.8% 2.8% 2.5% 2.4% 2.4% 2.2% 1.8% 1.7% 1.7% 1.4% 1.3% 1.1% 1.0% 0.7% 0.6% 0.5% 0.1% 0.0% Source: Thomson Reuters, Credit Suisse estimates Source: Thomson Reuters, Credit Suisse estimates U.S. Independent E&Ps 7

8 Figure 5: Short Interest (As of Last Settlement Date 11/09/16) % Short Interest Days to Cover 45% 40% Percentage Short Interest 35% 30% 25% 20% 15% 10% 5% 0% 39% 27% 25% 24% 21% 20% 17% 16% 16% 16% 15% 14% 14% 12% 12% 10% 9% 8% EPE SYRG CLR WLL DNR SN OAS CHK CIE CRZO CPE MUR LPI PDCE SWN PE KOS GPOR HES XOG FANG MRO AR CXO APA EQT RRC EGN NFX PXD NBL OXY APC DVN EOG 8% 7% 6% 6% 6% 6% 5% 5% 4% 4% 4% 4% 3% 2% 2% 2% 2% Days to Cover Source: the BLOOMBERG PROFESSIONAL service U.S. Independent E&Ps 8

9 Weekly Topics 3Q16 Earnings Review We exit 3Q16 earnings with corporates providing a more constructive view on longer term oil and gas fundamentals despite the uncertainty surrounding upcoming OPEC deliberations. Operationally, notable big cap names including NBL and EOG offered up Delaware type curve bumps to accommodate longer lateral drilling plans. Companies continue to highlight cash flow neutrality and long term double digit production CAGRs, which is underpinned by modest rig adds as efficiency gains on the drilling side help to offset the expected mild pricing pressure on completions. In terms of headline numbers specific to the quarter, we note that overall volumes were largely in-line to slightly ahead, coming in ~1.7% above consensus expectations (Figure 6), while volumetrically the beats were mainly driven by NGL and gas as oil production came in 1.0% above ours and 0.7% above consensus expectations (Figure 7), while gas volumes were a 1.4% beat relative to our estimates and 1.0% above consensus, and finally NGLs came in 5.9% above our estimates and 4.7% above consensus. Accounting for volumes associated with recent asset sales, our 2016 and 2017 production estimates remain largely unchanged (Figure 11), but given the lagged response time between activity picking up and production coming online, forecasted outspends have widened, especially in In 2016 at the strip, we expect our coverage universe to outspend cash flow by 19%, and by 15% in U.S. Independent E&Ps 9

10 Figure 6: 3Q16 Production Estimates - Actuals vs Estimates Total Production (Mboe/d) Ticker: Actual CS Estimate Diff (Mboe/d) % Diff Consensus Diff (Mboe/d) % Diff COP % % APC % % CHK % % OXY % % DVN % % EOG % % APA % % NBL % % MRO % % SWN % % EQT % % HES % % AR % % RRC % % PXD % % CLR % % MUR % % NFX % % CXO % % GPOR % % WLL % % EPE % % PDCE % % EGN % % SN % % LPI % % OAS % % FANG % % PE % % CRZO % % XOG % % CPE % % SYRG % % Total (Mboe/d): % % U.S. Independent E&Ps 10

11 Figure 7: 3Q16 Oil Production Estimates - Actuals vs Estimates Oil Production (Mbbl/d) Ticker: Actual CS Estimate Diff (Mbbl/d) % Diff Consensus Diff (Mbbl/d) % Diff COP % % OXY % % APC % % EOG % % MRO % % DVN % % APA % % HES % % PXD % % NBL % % CLR % % MUR % % CXO % % CHK % % WLL % % NFX % % EPE % % OAS % % EGN % % FANG % % PE % % PDCE % % CRZO % % LPI % % SN % % XOG % % CPE % % RRC % % SWN % % GPOR % % SYRG % % AR % % EQT % % Total (Mbbl/d): % % U.S. Independent E&Ps 11

12 Figure 8: 3Q16 Gas Production Estimates - Actuals vs Estimates 10/13/2016 Total Gas (MMcf/d) Ticker: Actual CS Estimate Diff (MMcf/d) % Diff Consensus Diff (MMcf/d) % Diff COP % % CHK % % SWN % % APC % % EQT % % NBL % % AR % % DVN % % EOG % % RRC % % APA % % OXY % % MRO % % GPOR % % CLR % % HES % % NFX % % MUR % % CXO % % PXD % % PDCE % % EPE % % SN % % WLL % % LPI % % CRZO % % EGN % % OAS % % XOG % % PE % % SYRG % % FANG % % CPE % % Total (MMcf/d): 25,655 25, % 25, % U.S. Independent E&Ps 12

13 Figure 9: 3Q16 US Gas Production - Actuals vs Estimates US Gas (MMcf/d) Ticker: Actual CS Estimate Diff (MMcf/d) % Diff CHK % SWN % APC % EQT % AR % DVN % COP % NBL % RRC % EOG % GPOR % CLR % APA % NFX % CXO % OXY % PXD % MRO % HES % PDCE % EPE % SN % WLL % LPI % CRZO % EGN % OAS % XOG % MUR % PE % SYRG % FANG % CPE % Total (MMcf/d): 20,408 20, % U.S. Independent E&Ps 13

14 Figure 10: 3Q16 NGL Production Estimates - Actuals vs Estimates NGL Production (Mbbl/d) Ticker: Actual CS Estimate Diff (Mbbl/d) % Diff Consensus Diff (Mbbl/d) % Diff APC % % DVN % % OXY % % EOG % % AR % % RRC % % CHK % % APA % % NBL % % PXD % % HES % % EQT % % SWN % % NFX % % WLL % % PDCE % % SN % % EPE % % LPI % % GPOR % % EGN % % PE % % FANG % % XOG % % CRZO % % Total (Mbbl/d): % % U.S. Independent E&Ps 14

15 Figure 11: CS Production Volume Estimate Changes (Mboe/d) Ticker: Current Previous Diff Current Previous Diff Current Previous Diff COP (6.5) (18.2) (53.1) APC (18.8) (14.9) (6.6) CHK OXY DVN (3.1) (16.4) (19.7) EOG APA NBL SWN (2.1) (11.6) (11.9) MRO EQT (1.2) HES (4.9) (10.2) (1.1) AR RRC (1.3) PXD (0.0) CLR MUR (0.7) NFX CXO WLL GPOR EPE PDCE (0.5) EGN (0.2) SN (0.4) (2.6) (2.9) OAS LPI CRZO FANG (0.2) PE XOG CPE (0.1) SYRG (0.0) Total: % Change 0% 1% 2% U.S. Independent E&Ps 15

16 Figure 12: CS US Oil Production Estimate Changes (Mbbl/d) Ticker: Current Previous Diff Current Previous Diff Current Previous Diff COP (3.9) (19.8) EOG APC (13.0) OXY (0.8) MRO PXD (2.3) (0.4) (0.6) CLR (1.3) DVN (0.4) (0.6) (2.6) HES (3.5) (5.8) APA (1.1) (6.2) (15.9) NBL WLL CXO (0.4) (3.9) CHK (0.6) NFX (2.0) (2.6) MUR (0.1) (2.5) EPE OAS EGN (0.1) (0.8) FANG (0.2) PE CRZO PDCE (0.5) LPI (0.2) SN (0.1) (0.9) (0.6) XOG (1.2) (1.5) CPE (0.2) (0.1) RRC (0.4) SWN (0.1) (0.2) (0.3) GPOR (0.1) (0.6) (0.7) SYRG AR (0.2) (0.4) (0.5) EQT (0.1) (0.2) (0.2) Total: (17.4) % Change -1% 2% 3% U.S. Independent E&Ps 16

17 Figure 13: CS US Gas Production Volume Estimate Changes (Mmcf/d) Ticker: Current Previous Diff Current Previous Diff Current Previous Diff CHK (14.6) SWN (15.5) (73.0) (75.9) APC (43.5) (137.1) (127.2) EQT DVN (1.7) (35.8) (24.5) AR (12.4) (29.7) (36.2) COP (2.6) (2.3) (97.7) NBL (26.5) (82.5) (98.1) RRC (5.8) (16.8) EOG GPOR (3.3) (9.5) CLR APA NFX OXY CXO PXD MRO (10.4) (17.0) HES (3.5) (27.9) (41.8) EPE PDCE (6.1) (5.4) SN (0.2) WLL LPI CRZO EGN (0.8) (5.0) (1.4) OAS MUR (4.3) (4.1) (4.1) XOG PE SYRG (0.8) (1.2) (1.0) FANG (3.3) (7.2) (9.3) CPE Total: (118.6) % Change 0% -1% 1% U.S. Independent E&Ps 17

18 Figure 14: CS Capex Estimate Changes ($MM) Ticker: Current Previous Diff Current Previous Diff Current Previous Diff COP $5,199 $5,431 ($232) $4,913 $4,864 $48 $5,084 $5,038 $47 APC $3,394 $3,294 $100 $4,129 $4,191 ($62) $4,597 $4,723 ($127) EOG $2,800 $2,600 $200 $4,500 $4,500 $0 $6,000 $6,000 $0 HES $2,339 $2,286 $53 $2,756 $2,738 $17 $3,342 $3,461 ($119) DVN $2,136 $2,037 $99 $2,892 $2,730 $163 $3,345 $3,172 $173 PXD $2,100 $2,100 $0 $2,750 $2,600 $150 $3,200 $3,200 $0 APA $2,030 $2,028 $3 $3,218 $3,208 $11 $3,998 $3,855 $142 AR $1,880 $1,880 $0 $1,900 $1,900 $0 $2,300 $2,300 $0 CHK $1,750 $1,700 $50 $2,200 $2,200 $0 $2,700 $2,400 $300 EQT $1,490 $1,490 $0 $2,200 $2,250 ($50) $2,615 $2,615 $0 NBL $1,450 $1,450 $0 $2,200 $1,700 $500 $2,700 $2,500 $200 MRO $1,432 $1,446 ($14) $2,217 $1,928 $289 $2,769 $2,479 $290 CXO $1,300 $1,200 $100 $1,525 $1,525 $0 $1,975 $1,800 $175 CLR $1,098 $1,098 $0 $2,074 $2,074 $0 $2,472 $2,472 $0 NFX $850 $850 $0 $1,000 $950 $50 $1,400 $1,350 $50 SWN $750 $750 $0 $1,050 $1,100 ($50) $1,300 $1,300 $0 MUR $626 $626 $0 $963 $963 $0 $1,297 $1,297 $0 RRC $569 $495 $74 $920 $840 $80 $1,300 $1,150 $150 WLL $550 $550 $0 $700 $700 $0 $1,050 $1,100 ($50) GPOR $525 $525 $0 $750 $750 $0 $950 $950 $0 EPE $490 $490 $0 $450 $450 $0 $550 $550 $0 EGN $485 $485 $0 $800 $650 $150 $850 $800 $50 PE $475 $475 $0 $650 $600 $50 $800 $800 $0 PDCE $450 $485 ($35) $700 $650 $50 $950 $950 $0 CRZO $435 $395 $40 $375 $375 $0 $450 $450 $0 FANG $425 $425 $0 $575 $575 $0 $800 $800 $0 LPI $420 $420 $0 $480 $400 $80 $470 $435 $35 OAS $400 $400 $0 $450 $375 $75 $550 $500 $50 XOG $380 $380 $0 $650 $650 $0 $750 $750 $0 SN $275 $275 $0 $300 $275 $25 $320 $295 $25 CPE $150 $140 $10 $280 $250 $30 $350 $325 $25 SYRG $145 $150 ($5) $325 $350 ($25) $400 $400 $0 Total: $38,799 $38,356 $442 $50,892 $49,311 $1,581 $61,634 $60,218 $1,416 % Change 1.2% 3.2% 2.4% U.S. Independent E&Ps 18

19 Figure 15: CS Cash Flow Estimate Changes at the CS Deck ($MM) Ticker: Current Previous Diff Current Previous Diff Current Previous Diff COP $4,270 $4,377 ($107) $7,675 $7,547 $127 $9,659 $9,879 ($220) APC $2,802 $2,659 $143 $5,495 $5,430 $65 $7,092 $6,922 $170 EOG $2,470 $2,485 ($15) $4,951 $4,782 $170 $7,288 $6,810 $478 APA $2,269 $2,055 $214 $3,463 $3,201 $261 $4,394 $4,520 ($126) NBL $1,753 $1,815 ($62) $2,196 $2,083 $113 $2,917 $2,684 $233 PXD $1,690 $1,721 ($31) $2,451 $2,510 ($59) $3,604 $3,732 ($128) DVN $1,483 $1,536 ($54) $2,895 $2,917 ($22) $4,223 $4,204 $19 CXO $1,426 $1,384 $42 $1,579 $1,578 $1 $2,214 $2,135 $78 CLR $1,238 $1,171 $67 $2,324 $2,222 $101 $3,143 $3,061 $83 AR $1,198 $1,169 $29 $1,265 $1,239 $26 $2,032 $1,986 $46 EQT $1,031 $1,052 ($22) $1,510 $1,510 $0 $2,219 $2,223 ($4) CHK $923 $975 ($52) $1,723 $1,811 ($88) $2,867 $2,315 $552 MRO $892 $835 $57 $2,220 $1,970 $250 $3,159 $2,792 $367 NFX $798 $806 ($9) $1,004 $944 $61 $1,544 $1,478 $66 EPE $749 $723 $26 $379 $349 $30 $409 $396 $13 MUR $730 $704 $26 $1,149 $1,250 ($101) $1,603 $1,649 ($46) HES $670 $574 $96 $1,888 $2,033 ($145) $2,884 $3,062 ($178) SWN $609 $649 ($40) $1,132 $1,254 ($122) $1,508 $1,726 ($218) RRC $541 $493 $48 $1,005 $967 $37 $1,552 $1,494 $57 WLL $527 $507 $20 $726 $703 $24 $1,070 $1,040 $30 PDCE $458 $465 ($7) $562 $561 $1 $891 $881 $10 GPOR $379 $353 $26 $505 $520 ($15) $912 $916 ($4) OAS $347 $350 ($2) $695 $569 $126 $752 $604 $148 LPI $327 $313 $14 $325 $289 $36 $426 $418 $8 FANG $317 $306 $11 $593 $579 $14 $931 $912 $18 CRZO $301 $291 $10 $375 $355 $20 $551 $495 $56 PE $283 $294 ($11) $564 $539 $25 $980 $941 $39 EGN $240 $257 ($17) $536 $517 $18 $851 $850 $1 SN $180 $186 ($7) $134 $159 ($25) $233 $267 ($34) CPE $141 $134 $7 $254 $239 $15 $422 $389 $33 XOG $140 $134 $5 $422 $430 ($8) $815 $785 $30 SYRG $45 $40 $5 $151 $154 ($2) $319 $314 $6 Total: $31,226 $30,817 $410 $52,147 $51,211 $936 $73,464 $71,880 $1,584 % Change 1.3% 1.8% 2.2% Capex ($MM): $38,799 $38,356 $442 $50,892 $49,311 $1,581 $61,634 $60,218 $1,416 Outspend (% of CF) -20% -20% 2% 4% 19% 19% U.S. Independent E&Ps 19

20 Figure 16: 2016 & 2017 Outspends at the Strip Ticker: Capex Cash Flow Outspend Capex Cash Flow Outspend COP $5,199 $4,274 ($925) $4,913 $6,421 $1,508 APC $3,394 $2,902 ($492) $4,129 $4,456 $327 EOG $2,800 $2,469 ($331) $4,500 $4,085 ($415) HES $2,339 $688 ($1,651) $2,756 $1,459 ($1,297) DVN $2,136 $1,479 ($657) $2,892 $2,319 ($573) PXD $2,100 $1,696 ($404) $2,750 $1,959 ($791) APA $2,030 $2,257 $227 $3,218 $2,965 ($254) AR $1,880 $1,206 ($674) $1,900 $1,204 ($696) CHK $1,750 $918 ($832) $2,200 $1,479 ($721) EQT $1,490 $1,101 ($389) $2,200 $1,375 ($824) NBL $1,450 $1,749 $299 $2,200 $1,816 ($384) MRO $1,432 $901 ($531) $2,217 $1,677 ($540) CXO $1,300 $1,422 $122 $1,525 $1,456 ($69) CLR $1,098 $1,240 $143 $2,074 $1,966 ($108) NFX $850 $797 ($53) $1,000 $834 ($166) SWN $750 $586 ($164) $1,050 $1,001 ($49) MUR $626 $665 $39 $963 $981 $18 RRC $569 $540 ($29) $920 $877 ($43) WLL $550 $526 ($24) $700 $527 ($173) GPOR $525 $377 ($148) $750 $471 ($279) EPE $490 $750 $260 $450 $350 ($100) EGN $485 $242 ($243) $800 $460 ($340) PE $475 $284 ($191) $650 $471 ($179) PDCE $450 $458 $8 $700 $486 ($214) CRZO $435 $306 ($129) $375 $313 ($62) FANG $425 $318 ($107) $575 $501 ($74) LPI $420 $327 ($93) $480 $289 ($191) OAS $400 $365 ($35) $450 $482 $32 XOG $380 $138 ($242) $650 $361 ($289) SN $275 $187 ($88) $300 $91 ($209) CPE $150 $141 ($9) $280 $223 ($57) SYRG $145 $54 ($91) $325 $134 ($191) Total: $38,799 $31,364 ($7,435) $50,892 $43,490 ($7,402) Outspend (% of Cash Flow) -19.2% -14.5% U.S. Independent E&Ps 20

21 NBL US Onshore Long-Term Outlook Update Earlier this week, NBL hosted a US onshore outlook call which featured long term capital spending, cash flow, and production guideposts as well as bumps to type curves in both the DJ and the Delaware, where NBL expects to focus the majority of its capital. In tandem, we raised our target price to $46 (from $44 previously). NBL expects to deliver a 23-29% US onshore oil CAGR through 2020 driven by increased type curves and inventory in the Delaware and DJ Basins. While 2017 production guidance of Mboe/d was below our prior Mboe/d estimate, US onshore oil production is now expected to increase 13% in 2017 and 20% in 2018, which was higher than our prior estimates of 10% and 19%, respectively. Heading into the call, the main pushback on NBL had been the company s willingness to accelerate US onshore as the bulk of oil growth had come from the GoM over the past two years. The company took those concerns head on, having recently added a rig each to its Delaware and Eagle Ford programs, and announced a third going to the Delaware in a few weeks. NBL added substantially more inventory in the Delaware compared to when the asset was acquired in 1H15, and longer lateral development and increased completion intensity promise further upside given the performance of Generation 4 completions, and additional well catalysts expected throughout In the DJ, NBL increased EUR s per lateral foot by 20% in Wells Ranch and Mustang and 15% in East Pony. NBL plans to add a third operated rig in mid-2017, and anticipates running a 5-6 rig program longer term. Delaware Update Similar to Southern Delaware Basin peers, NBL added the 3rd Bone Spring as a development target. The company's initial spacing assumptions appear conservative relative to peers at four wells per section, which leaves location upside as NBL delineates its position. Scaling peer 3rd Bone Spring results to a 7,500 ft lateral, we present our production and cume estimates in Figure 17. We note that NBL assumes a 71% oil EUR (3-stream), which is slightly oilier than recent peer results, notably CXO, which released a pair of 3Q16 wells that peaked at 1,909 boe/d from 4,865 ft laterals, but exhibited a 64% oil cut (2-stream). U.S. Independent E&Ps 21

22 Production (boe/d) Cume (boe) 18 November 2016 Figure 17: 3rd Bone Spring Production and Cume Cume Production 1, ,000 1, ,000 1,200 1, , , , , Months Online 0 Source: HPDI, Credit Suisse estimates Figure 18: CXO 3Q16 3rd Bone Spring Results Figure 19: NBL Delaware Completions and CXO 3 rd Bone Spring Locations Source: CXO 3Q16 Earnings Presentation Source: HPDI, Credit Suisse Estimates NBL also unveiled type curves for the the Wolfcamp B and C in addition to the 3rd Bone Spring in its updated slide, and expects the 3rd Bone Spring will be a near-term target for U.S. Independent E&Ps 22

23 Fluid Concentration (bbls/ft) Proppant Loading (lbs/ft) 18 November 2016 the company. We note that the Wolfcamp A type curve assumes similar productivity per lateral foot as the previous 700 Mboe, 4,500 ft EUR (Figure 20). Figure 20: NBL Delaware Basin Type Curves (7,500 ft lateral) Following the trend of offset operators, NBL highlighted that iterative generations of completion design have been driving type curve outperformance in the Delaware, with Generation 4 wells materially outperforming the company's revised longer lateral Wolfcamp A type curve. In an attempt to understand what could be causing the outperformance, below we note how slickwater completions appear to be the major driving factor from Gen 3 to Gen 4, as the Calamity Jane #2101H helps the Gen 4 average, having produced a massive 82 Mbbls oil and 137 Mboe total after only two months online (60% oil, two-stream see Figure 21). Figure 21: NBL vs. ROSE Well Result Evolution and Completion Design Source: NBL, Frac Focus, HPDI, Credit Suisse estimates Target EUR (Mboe) Mix (oil/ngl/gas) Well Cost ($MM) 3rd Bone Spring % / 15% / 15% $6.3 Wolfcamp A 1,200 70% / 15% / 15% $8.5 Wolfcamp B 1,135 70% / 15% / 15% $8.6 Wolfcamp C % / 15% / 15% $8.8 3,500 3,000 2,500 2,000 1,500 1, ROSE Completions 0 Nov-13 Jun-14 Dec-14 Jul-15 Jan-16 Aug-16 Mar ROSE Completions Completion Date NBL Completions NBL Completions 0.0 Nov-13 Jun-14 Dec-14 Jul-15 Jan-16 Aug-16 Mar-17 Completion Date U.S. Independent E&Ps 23

24 Figure 22: NBL vs. ROSE Well Performance Cumulative Production (Mboe - 2 Stream) ROSE NBL ROSE (7.5k ft) Months on Production Source: HPDI, Credit Suisse estimates The Calamity Jane #2101H was completed with an impressive 3,110 lbs/ft of proppant and utilized ~76 bbls/ft of fluid, relative to other NBL operated results averaging 2,253 lbs/ft and ~45 bbls/ft. Additionally, with a 2017 focus turned to longer lateral development, in Figure 22 we also show how one ROSE operated 7,500' well in the Delaware is materially outperforming ROSE shorter laterals and roughly in-line with NBL operated performance (on shorter laterals). Going forward, we see line of sight on further type curve improvements as NBL's completion design is coupled with longer laterals. DJ Update Similar to the Delaware above, we also reviewed the other major US onshore area for capital deployment, the DJ, with a special focus on the East Pony and Wells Ranch IDPs. Given the breadth of results to look at, we randomly sampled 10 wells per year from each operating area going back to the beginning of 2014 (Figure 23). Results would show that slickwater completion styles appear to be driving the majority of East Pony outperformance (Figure 24), while longer laterals are driving more efficient production from the Wells Ranch area (all 2016 wells sampled were longer than 9,000' Figure 25). While arguably a more mature and well understood play, we nevertheless remain encouraged as NBL tests further enhancements to drilling and completion designs. Early results from 2016 would suggest that while missing the step change in productivity seen from 2015 vintage wells relative to 2014 wells, 2016 is nevertheless on track to perform in-line or better than 2015 and far above 2014 vintage wells. U.S. Independent E&Ps 24

25 Lateral Length (Productive ft) Fluid Concentration (bbls/ft) 18 November 2016 Figure 23: NBL DJ Well Design Evolution and Production Results 50.0 East Pony Nov-13 Jun-14 Dec-14 Jul-15 Completion Date Jan-16 Aug-16 Wells Ranch ,000 10,000 8,000 6,000 4,000 2,000 0 Nov-13 Jun-14 Dec-14 Jul-15 Jan-16 Aug-16 Mar-17 Completion Date Source: NBL, Frac Focus, HPDI, Credit Suisse estimates Figure 24: NBL East Pony Well Results by Vintage Cumulative Production (Mboe - 2 Stream East Pony 9.5k ft Lateral (2015) Months on Production Source: HPDI, Credit Suisse estimates (Non-9.5k ft laterals range from 4-5k ft) Figure 25: NBL Wells Ranch Well Results by Vintage Cumulative Production (Mboe - 2 Stream) (4,500' lateral) 2014 (9,000' lateral) 2016 (9,000' lateral) 2014 (4,500' lateral) 2015 (9,000' lateral) 2015 (7,000' lateral) Months on Production Source: HPDI, Credit Suisse estimates U.S. Independent E&Ps 25

26 Wells of the Week A Closer Look at the Northern Powder River Basin Hotspot Following our review of the Southern PRB Hotspot (Wells of the Week Looking Into CHK's LT Oil Growth Driver), we want to take a closer look at the northern PRB hotspot, located near the Campbell Converse county line, as this play has been increasingly discussed by public operators such as EOG and DVN during 3Q earnings. Figure 26: DJ and PRB Hotspots Source: CHK Most of the wells near the northern hotspot drilled to date target the Parkman or the Turner, and of the two, the Turner is believed to have better economics despite the higher associated well costs from drilling a deeper target formation. As a result, we focus our analysis on the Turner Sandstone. Figure 27: Drillable Formations in the PRB Figure 28: IRR by Drilling Zones Source: DVN Source: DVN The most active players targeting Turner are EOG, DVN, and two private operators Peak Powder River Resources and Ballard Petroleum Holdings. DVN holds the biggest acreage U.S. Independent E&Ps 26

27 position in the basin (470k net acres), followed by EOG (who holds 200k net acres post Yates acquisition). Figure 29: Historic Turner by Peak Oil (2013+) Source: HPDI Rapid GOR Shift The first thing we noticed from historical production data is the significant differences in GOR from just moving a few miles within the Southern Campbell/Northern Converse areas. Among the 192 wells we looked at, all are located within ~30 miles of each other, but have oil cuts ranging from 11% to 96% (on cumulative production to date). Figure 30: Significant GOR Shift Seen within A Few Miles Converse Campbell 0% 20% 40% 60% 80% 100% Oil Cut (%) Source: HPDI We further analyzed the distribution of oil cuts across the county line acreage by breaking our well sample into four buckets: below 40%, 40% - 60%, 60% - 80% and over 80% and mapping where these wells are located. U.S. Independent E&Ps 27

28 Figure 31: Historical Turner Wells with Oil Cut Below 40% Figure 32: Historical Turner Wells with Oil Cut Between 40% and 60% Source: HPDI Source: HPDI Figure 33: Historical Turner Wells with Oil Cut Between 60% and 80% Figure 34: Historical Turner Wells with Oil Cut Above 80% The distribution of oil cuts across the county line acreage seems to suggest a similar pattern to what we see in the DJ basin (Figure 35) and southern PRB hotspot (Figure 36) some form of concentric elliptical boundaries, across which the hydrocarbon mix characteristics change. The drastic shift in GOR is likely due to a common phenomenon associated with hotspots the closer to the center of the hotspot, the more heated, cooked, and pressurized the reservoirs are, leading to higher gas cut. U.S. Independent E&Ps 28

29 Figure 35: DJ GOR Map Figure 36: Southern PRB Hotspot GOR Map Source: SYRG Source: CHK To that point, the southern hotspot in the PRB is believed to be hotter than the north, leading to higher pressure compared to the northern one. As seen in Figure 19, while the GOR gradually increases throughout the life of the well, southern hotspot wells have higher GORs compared to wells in both Converse and especially in Campbell. Further, and unsurprisingly, southern hotspot wells have higher IP rates compared to Converse and Campbell given the gassier mix. Figure 37: GOR Shift Over Life of Well for Turner Wells CHK Southern Hotspot GOR Campbell GOR Converse GOR 5,200 4,700 4,200 3,700 3,200 2,700 2,200 1,700 1, Source: Credit Suisse estimates, HPDI, CHK U.S. Independent E&Ps 29

30 Figure 38: Turner Type Curves 1,200 Turner-CHK Type Curve Turner-Converse Type Curve Turner-Campbell Type Curve 1, Daily Production (boe/d) Source: HPDI Based on observations and historical well results, we estimate oil cut distributions for respective operators near the northern hotspot. Based on our work, legacy EOG acreage is mainly located in the high GOR area (oil cut below 60%), while the recently acquired Yates acreage sits in a lower GOR area (oil cut above 80%). DVN, Ballard and Peak's acreage also sit in areas where oil cut is above 60%. Figure 39: Estimated Heat Map Based on Historical Wells Source: Credit Suisse estimates, HPDI Core of County Line Acreage Additionally, we wanted to look at where the best performing wells are near the county line by comparing individual historical production data to our modeled EOG PRB type curve. U.S. Independent E&Ps 30

31 Figure 40: Modeled EOG PRB Type Curve % Oil 37% % NGL 17% % Gas 46% Production (boe/d) 1, IP-30: EUR: Well Cost: ATAX IRR: NPV/well: 1,240 boe/d 1,165 Mboe $4.9mm 27.4% $3.2mm Years Cumulative Production (Mboe) Source: EOG, Credit Suisse estimates We found 36 wells that are currently trending above our PRB type curve. It doesn't come as a surprise that a good proportion of these wells are located near the northern hotspot, as a result of the reservoir being more heated and pressurized. Figure 41: PRB Wells Historical Cume Production Figure 42: Outperforming PRB Wells Cumulative Production (MBoe) Source: Credit Suisse estimates, HPDI Source: Credit Suisse estimates, HPDI However, to the western portion of Campbell, there are a few wells that have oil cuts between 60% 80%. Therefore, taking into consideration GOR and well performance, we believe the sweet spot of the county line acreage is in southwest Campbell (Figure 43). EOG, Peak and Ballard Energy have been the most active players in that region historically. U.S. Independent E&Ps 31

32 Figure 43: Sweet Spot of Northern Hotspot Acreage Figure 44: EOG PRB Acreage Post Yates Acquisition Source: Company data Improving Well Performance over Time One additional thing to note is that most of wells trending above type curves are drilled recently (2015+). We can see in Figure 20 that well performances have been improving over time, which is most likely driven by longer lateral length. While there is no data to U.S. Independent E&Ps 32

33 verify trends in lateral length as it is not reported in WY, both DVN and EOG have commented about longer lateral driving improving well economics. Figure 45: Vintage Type Curve By Year Source: HPDI Last Six Wells of the Week: 10/28/2016: A Look at EQT Completion Designs 10/21/2016: Looking Into CHK's LT Oil Growth Driver 10/14/2016: Reviewing FANG's Completion Design 10/07/2016: PE's Completion Evolution, Monster-Fracs, and Delaware Read-through 09/30/2016: An Initial Read on EGN s Upsized Completions 09/23/2016: EOG's Longer Laterals in the Eagle Ford West U.S. Independent E&Ps 33

34 $51.27 $53.03 $2.85 $53.38 $53.60 $53.65 $ $54.06 $54.24 $54.72 $3.07 $54.90 $55.19 $55.23 $55.39 $3.26 $55.41 $56.27 $57.17 $3.36 $57.34 $58.29 $58.57 $3.63 $59.51 $61.00 $61.38 $3.98 $61.39 $61.87 $62.23 $62.85 $4.36 $65.25 $ November 2016 Valuation Snapshot Implied Oil and Gas Prices Figure 46: Equity Implied Gas Prices As of 11/18/16 $5.00 Gas Median $ Strip $ Strip $3.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 Figure 47: Equity Implied Oil Prices As of 11/18/16 WTI Oil Median $ Strip $ Strip $48.80 $80.00 $70.00 $60.00 $50.00 $40.00 $30.00 $20.00 $10.00 $0.00 U.S. Independent E&Ps 34

35 Figure 48: E&P Upside/Downside to NAV 75% E&P Median: 23% Upside 1% -4% -1% 4% 51% 50% 25% 8% 9% 10% 13% 17% 19% 20% Upside / Downside at the Strip 23% 23% 23% 23% 24% 25% 25% 25% 28% 29% 29% 29% 30% 31% 32% 33% 35% 41% 42% 0% -25% -50% -33% -29% Figure 49: E&P Upside/Downside to NAV at CS Deck and Strip 25% Mkt Cap Wtd. Avg. AR 0% (25%) OXY APC EQT FANG NBL DVN PE CPE PXD WLL CXO EGN HES NFX APA OAS PDCE MRO SYRG EOG CRZO RRC MUR XOG GPOR CLR (50%) LPI SWN (75%) SN (100%) DNR EPE CHK (40%) (30%) (20%) (10%) 0% 10% 20% 30% 40% 50% 60% Upside / Downside at the CS Deck U.S. Independent E&Ps 35

36 4.0x 4.6x 7.9x 8.2x 8.7x 8.9x 8.9x 9.4x 9.7x 10.3x 10.4x 10.5x 10.5x 10.6x 11.0x 11.6x 12.4x 12.8x 13.1x 13.2x 13.8x 14.2x 14.8x 16.8x 16.9x 16.9x 17.9x 18.0x 19.6x 21.3x 22.0x 23.6x 31.4x 4.8x 5.2x 8.3x 9.3x 9.3x 9.4x 9.6x 9.8x 10.0x 10.6x 10.8x 10.9x 11.0x 11.7x 11.7x 11.8x 12.6x 12.7x 12.9x 13.9x 14.3x 14.8x 15.0x 17.5x 17.7x 17.8x 19.0x 19.3x 20.9x 21.3x 22.7x 23.4x 30.5x 18 November 2016 Figure 50: 2016 EV to EBITDA (unhedged at the strip, $45.57/bbl WTI, $2.76/MMbtu) 32.0x 30.0x E&P Median: 12.6x 28.0x 26.0x Oil Focused: 12.8x 24.0x Gas Focused: 10.9x 22.0x 20.0x 18.0x 16.0x 14.0x 12.0x 10.0x 8.0x 6.0x 4.0x 2.0x 0.0x Figure 51: 2016 EV to EBITDA (hedged at the CS Deck, $42.18/bbl WTI, $2.45/MMbtu gas) 32.0x 30.0x E&P Median: 12.4x 28.0x 26.0x 24.0x Oil Focused: 13.0x Gas Focused: 10.5x 22.0x 20.0x 18.0x 16.0x 14.0x 12.0x 10.0x 8.0x 6.0x 4.0x 2.0x 0.0x U.S. Independent E&Ps 36

37 5.3x 6.0x 6.3x 6.5x 6.6x 6.6x 6.8x 6.9x 7.1x 7.3x 7.8x 7.8x 7.8x 7.9x 7.9x 8.0x 8.0x 8.0x 8.1x 8.4x 9.3x 9.4x 9.7x 10.0x 10.1x 10.1x 10.2x 11.2x 11.4x 12.1x 12.1x 12.4x 12.9x 5.9x 7.5x 7.6x 7.9x 8.2x 8.4x 8.6x 8.6x 8.8x 9.3x 9.4x 9.4x 9.4x 9.5x 9.6x 9.7x 10.0x 10.3x 11.0x 11.2x 11.4x 11.5x 11.5x 11.8x 12.4x 12.7x 12.8x 13.3x 13.9x 14.1x 14.4x 15.2x 15.9x 18 November 2016 Figure 52: 2017 EV to EBITDA (unhedged at the strip, $48.69/bbl WTI, $3.00/MMbtu) 16.0x E&P Median: 10.0x 14.0x 12.0x Oil Focused: 10.6x Gas Focused: 9.4x 10.0x 8.0x 6.0x 4.0x 2.0x 0.0x Figure 53: 2017 EV to EBITDA (hedged at the CS Deck, $55.00/bbl WTI, $3.25/MMbtu gas) 14.0x 12.0x 10.0x E&P Median: 8.0x Oil Focused: 8.2x Gas Focused: 7.9x 8.0x 6.0x 4.0x 2.0x 0.0x U.S. Independent E&Ps 37

38 3.5x 4.1x 4.1x 4.2x 4.6x 4.8x 5.0x 5.0x 5.1x 5.2x 5.3x 5.3x 5.5x 5.5x 5.6x 5.8x 5.9x 5.9x 6.0x 6.3x 6.3x 6.4x 6.5x 6.6x 6.7x 7.0x 7.1x 7.6x 8.0x 8.1x 8.1x 8.2x 8.8x 5.0x 5.7x 6.0x 6.6x 7.2x 7.2x 7.3x 7.4x 7.4x 7.5x 7.6x 7.7x 8.0x 8.2x 8.2x 8.5x 8.8x 9.1x 9.1x 9.4x 9.5x 9.6x 9.6x 9.8x 9.9x 10.1x 11.1x 10.4x 10.6x 10.8x 11.1x 11.1x 11.6x 18 November 2016 Figure 54: 2018 EV to EBITDA (unhedged at the strip, $50.83/bbl WTI, $2.94/MMbtu) 14.0x 12.0x 10.0x E&P Median: 8.8x Oil Focused: 8.8x Gas Focused: 8.8x 8.0x 6.0x 4.0x 2.0x 0.0x Figure 55: 2018 EV to EBITDA (hedged at the CS Deck, $62.50/bbl WTI, $3.50/MMbtu gas) 9.0x 8.0x 7.0x E&P Median: 5.9x Oil Focused: 5.9x Gas Focused: 5.9x 6.0x 5.0x 4.0x 3.0x 2.0x 1.0x 0.0x U.S. Independent E&Ps 38

39 Figure 56: Debt Adjusted Cash Flow Per Share ( E) 100% 75% E&P Median: 13.1% Gas-Focused: 11.9% Oil-Focused: 12.5% 61% 76% 83% 50% 25% 0% -25% -50% -37% -31% -16% -7% -5% -2% -1% 1% 2% 6% 7% 8% 8% 10% 11% 12% 13% 13% 17% 18% 19% 22% 23% 25% 26% 29% 30% 31% 33% 35% Figure 57: 2016 Net Debt to EBITDA 8.0x CS Deck Futures Strip Median at CS Deck Median at Strip Median at CS Deck: 2.7x Median at Strip: 2.7x 6.0x 4.0x 2.0x 0.0x 2016 Price Scenario CS Strip WTI Oil $42.18 $45.57 NYMEX Gas $2.45 $2.76 U.S. Independent E&Ps 39

40 Figure 58: 2017 Net Debt to EBITDA 8.0x 7.0x 6.0x CS Deck Futures Strip Median at CS Deck Median at Strip Median at CS Deck: 1.8x Median at Strip: 2.3x 5.0x 4.0x 3.0x 2.0x 1.0x 0.0x 2017 Price Scenario CS Strip WTI Oil $55.00 $48.69 NYMEX Gas $3.25 $3.00 U.S. Independent E&Ps 40

41 Figure 59: Net Debt (as a % of EV) Current Net Debt (% of EV) EXXI SGY REXX CRK CRC WTI XCO AREX EPE CIE SN DNR JONE CHK WLL BBG HK OAS CNX KOS SM SWN AR CRZO WPX ECA RRC ECR COP MUR MRO NBL DVN LPI CLR APC CWEI APA NFX HES QEP XOG GPOR RSPP EOG COG OXY EQT CXO XEC PE FANG PXD EGN RICE CPE SYRG PDCE UPL 20% 19% 19% 17% 16% 12% 10% 9% 9% 9% 8% 6% 5% 4% 2% 2% 1% 43% 42% 40% 39% 38% 38% 36% 32% 31% 31% 31% 31% 29% 29% 29% 29% 28% 27% 26% 24% 24% 66% 65% 61% 57% 53% 82% 80% 80% 78% 76% 75% 71% 90% 89% 98% 96% 0% 20% 40% 60% 80% 100% U.S. Independent E&Ps 41

42 Figure 60: 2016 Outspend at the CS Deck ($42.18 WTI/$2.45 NYMEX) 200% 2016 Outspend (% of CF) Group Outspend 150% 100% 50% 0% (50%) Figure 61: 2017 Outspend at the CS Deck ($55.00 WTI/$3.25 NYMEX) 2017 Outspend (% of CF) Group Outspend 140% 120% 100% 80% 60% 40% 20% 0% (20%) (40%) (60%) U.S. Independent E&Ps 42

43 Hedging Oil Figure 62: 2016 Oil Volumes Hedged $ % 4% 7% 22% 25% 27% -7% -21% -27% 30% 20% 19% 42% -12% -2% -35% -3% -11% -70% -54% -16% -13% -11% -36% -31% -4% -10% -26% 8% 2% 2% 7% 19% 20% 21% 26% 24% 33% 33% 36% 36% 45% 46% 50% 52% 57% 60% 49% 50% 40% 4% 79% 62% 74% 15% 11% 26% 140% % Volumes Hedged % Short Put (on 3-way Collars) % Short Call (on 3-way Collars) Average Floor Price ($/bbl) Average Ceiling Price ($/bbl) Average Put Price ($/bbl) Average Call Price ($/bbl) 120% 100% 80% 60% 40% 20% 0% -20% -40% -60% 48% -15% 57% 58% 58% -49% 61% 67% 69% 71% -20% 75% -42% 76% 80% -61% 83% 23% 63% 93% 25% 77% -15% 63% 40% 34% 84% -63% $ $90.00 $80.00 $70.00 $60.00 $ % $40.00 Figure 63: 2017 Oil Volumes Hedged 100% % Volumes Hedged % Short Put (on 3-way Collars) % Short Call (on 3-way Collars) Average Floor Price ($/bbl) Average Ceiling Price ($/bbl) Average Put Price ($/bbl) Average Call Price ($/bbl) $ % 60% $ % $ % 0% $ % $ % -60% -80% $50.00 $40.00 U.S. Independent E&Ps 43

44 Gas Figure 64: 2016 Gas Volumes Hedged $6.00 $5.00 2% 2% -1% 14% 17% -6% 21% 21% -28% 23% -13% -13% -48% -32% -39% -11% -4% -3% -18% 2% 2% 8% 25% 27% 28% 29% 30% 32% 32% 13% 21% 39% 40% 40% 49% 53% 44% 54% 58% 44% 75% 66% 63% 12% 62% 65% 25% 70% 112% 5% % Volumes Hedged % Short Put (on 3-way Collars) % Short Call (on 3-way Collars) Average Floor Price ($/Mmbtu) Average Ceiling Price ($/Mmbtu) Average Put Price ($/Mmbtu) Average Call Price ($/Mmbtu) 140% 120% 100% 80% 60% 40% 20% 0% -20% -40% 25% 5% 21% -13% 26% 27% 31% 35% 38% -2% 41% 63% 67% 72% -52% 75% -17% 80% 5% 77% 85% 119% $4.00 $3.00 $2.00 $ % -80% $0.00 Figure 65: 2017 Gas Volumes Hedged % Volumes Hedged % Short Put (on 3-way Collars) % Short Call (on 3-way Collars) Average Floor Price ($/Mmbtu) Average Ceiling Price ($/Mmbtu) Average Put Price ($/Mmbtu) Average Call Price ($/Mmbtu) 140% 120% 100% 80% $10.00 $9.00 $8.00 $ % $ % $ % $4.00 0% $ % $ % $ % $0.00 U.S. Independent E&Ps 44

45 Oil and NGL Macro Figure 66: Regional Oil Differentials to WTI - As of 11/18/16 WTI-Brent Mid-Cush Bakken-WTI EF Light-WTI /3/2012 3/3/2012 5/3/2012 7/3/2012 9/3/ /3/2012 1/3/2013 3/3/2013 5/3/2013 7/3/2013 9/3/ /3/2013 1/3/2014 3/3/2014 5/3/2014 7/3/2014 9/3/ /3/2014 1/3/2015 3/3/2015 5/3/2015 7/3/2015 9/3/ /3/2015 1/3/2016 3/3/2016 5/3/2016 7/3/2016 9/3/ /3/2016 1/6/2012 3/6/2012 5/6/2012 7/6/2012 9/6/ /6/2012 1/6/2013 3/6/2013 5/6/2013 7/6/2013 9/6/2013 Differential ($ per Bbl) 11/6/2013 1/6/2014 3/6/2014 5/6/2014 7/6/2014 9/6/ /6/2014 1/6/2015 3/6/2015 5/6/2015 7/6/2015 9/6/ /6/2015 1/6/2016 3/6/2016 5/6/2016 7/6/2016 9/6/ /6/2016 Price ($ per Bbl) Percentage of WTI (%) Source: the BLOOMBERG PROFESSIONAL service, Credit Suisse estimates Figure 67: NGL Composite Prices (at Mt. Belvieu) - As of 11/18/16 NGL as a Percentage of WTI (%) Propane ($ per Bbl) Normal Butane ($ per Bbl) Isobutane ($ per Bbl) Ethane ($ per Bbl) Natural Gasoline ($ per Bbl) % % 40% 35% 30% 60 25% % 15% 10% 5% 0 0% Source: the BLOOMBERG PROFESSIONAL service, Credit Suisse estimates U.S. Independent E&Ps 45

46 1/6/2012 3/6/2012 5/6/2012 7/6/2012 9/6/ /6/2012 1/6/2013 3/6/2013 5/6/2013 7/6/2013 9/6/ /6/2013 1/6/2014 3/6/2014 5/6/2014 7/6/2014 9/6/ /6/2014 1/6/2015 3/6/2015 5/6/2015 7/6/2015 9/6/ /6/2015 1/6/2016 3/6/2016 5/6/2016 7/6/2016 9/6/ /6/2016 Differential ($ per MMBtu) Gas Macro Figure 68: US Natural Gas Storage - As of 11/11/16 Change Change Differential 11/11/2016 Week Ago % Bcf Year Ago % Bcf 5-Year Avg % Bcf East (0.2%) (2) % % 18 Midwest 1,155 1, % 7 1, % 33 1, % 62 Mountain % % % 48 Pacific % (13.9%) (53) 369 (11.1%) (41) South Central 1,363 1, % 20 1, % 18 1, % 129 Total U.S. 4,047 4, % 30 3, % 51 3, % 216 Billion Cubic Feet 4,500 4,000 3,500 3,000 2,500 2,000 1,500 5-Yr Range Yr Avg Total U.S. Working Gas In Storage 1, Calendar Week Source: EIA, Credit Suisse estimates Figure 69: Select Northeast Gas Price Differential to Henry Hub - As of 11/18/ Columbia TCO to HH Leidy to HH Dominion South to HH M2 to HH Source: the BLOOMBERG PROFESSIONAL service U.S. Independent E&Ps 46

47 Focus on Capex and Costs Figure 70: 2016 and 2017 Capex per boe 2016 Capex/boe 2017 Capex/boe 2016 Median 2017 Median $50 $45 $40 $35 $30 $25 $20 $15 $10 $5 $0 Figure 71: Cash Costs per boe $ Cash Costs/boe 2016 Cash Costs/boe 2017 Cash Costs/boe 2015 Median 2016 Median 2017 Median $30 $25 $20 $15 $10 $5 $0 U.S. Independent E&Ps 47

48 Figure 72: Large Cap Oil Headline Cashflow Cash Margins - Hedged ($/boe, ) $40 HES MUR PXD CVX OXY COP CLR XOM APA CXO EOG NBL MRO APC DVN CHK $35 $30 $25 $20 $15 $10 $5 $0 -$ ($48.76/bbl) 2016 ($42.18/bbl) 2017 ($55.00/bbl) 2018 ($62.50/bbl) Figure 73: SMID Cap Oil Headline Cashflow Cash Margins - Hedged ($/boe, ) $40 SYRG OAS CRZO EGN DNR EPE PDCE LPI FANG WLL PE CPE BCEI SN XOG $35 $30 $25 $20 $15 $10 $5 $ ($48.76/bbl) 2016 ($42.18/bbl) 2017 ($55.00/bbl) 2018 ($62.50/bbl) U.S. Independent E&Ps 48

49 Figure 74: Gas Cash Margins ($/Mcfe, ) $2.5 AR RRC SWN EQT GPOR $2.0 $1.5 $1.0 $0.5 $ ($2.67/Mcf) 2016 ($2.45/Mcf) 2017 ($3.25/Mcf) 2018 ($3.50/Mcf) ' U.S. Independent E&Ps 49

50 Figure 75: Historical Lease Operating Expense ($/boe) 3Q16/2Q16 3Q16/3Q15 4Q15 1Q16 2Q16 3Q16 QoQ YoY Majors COP $12.5 $12.6 $12.4 $11.8 (5%) (6%) CVX $12.8 $12.4 $12.3 $11.2 (9%) (13%) XOM $10.8 $9.5 $9.5 $9.5 (1%) (17%) OXY $10.1 $10.3 $10.2 $10.8 6% (2%) Median $11.6 $11.3 $11.2 $11.0 (2%) (8%) Sequential Change (3%) (3%) (1%) (2%) Large Cap E&P APA $10.1 $8.7 $8.6 $9.5 11% 5% APC $3.2 $2.8 $2.8 $2.8 (2%) (24%) AR $0.5 $0.4 $0.5 $0.5 7% 3% CHK $3.6 $3.4 $3.0 $2.8 (8%) (32%) CLR $3.9 $3.7 $3.7 $3.5 (6%) (12%) CXO $10.2 $7.3 $5.8 $5.0 (15%) (50%) DVN $7.6 $7.1 $7.1 $6.7 (5%) (18%) EOG $4.7 $4.8 $4.4 $4.4 2% (18%) HES $14.1 $12.9 $15.4 $14.0 (9%) 4% MRO $5.7 $5.4 $5.3 $4.3 (18%) (27%) MUR $10.2 $8.9 $10.2 $7.7 (25%) (20%) NBL $3.8 $4.3 $3.1 $3.3 9% (12%) PXD $9.4 $7.8 $6.7 $6.4 (4%) (34%) Median $5.7 $5.4 $5.3 $4.4 (16%) (25%) Sequential Change (3%) (6%) (2%) (16%) SMID Cap E&P CPE $6.5 $6.2 $6.0 $6.5 9% (19%) CRZO $6.2 $6.3 $6.1 $6.5 6% (4%) DNR $19.3 $16.2 $17.0 $ % 9% EGN $8.8 $8.5 $7.3 $7.9 8% (15%) EPE $4.5 $4.4 $4.9 $5.1 2% 18% EQT $0.7 $0.5 $0.6 $0.5 (10%) (26%) FANG $5.1 $5.2 $5.6 $5.4 (4%) (24%) GPOR $5.7 $5.2 $5.4 $5.6 4% (7%) LPI $5.8 $4.9 $4.4 $3.9 (13%) (37%) NFX $8.4 $8.1 $8.4 $8.6 2% 0% OAS $6.9 $6.8 $7.0 $8.0 14% 4% PDCE $4.8 $5.1 $4.7 $5.0 7% (15%) PE $5.6 $5.3 $4.4 $4.1 (5%) (46%) RRC $1.3 $1.1 $0.9 $0.9 2% (39%) SN $8.7 $8.7 $8.8 $8.2 (7%) (1%) SWN $4.4 $4.2 $4.0 $4.0 (2%) (6%) SYRG $4.4 $4.1 $6.8 $3.8 (43%) (18%) WLL $8.4 $8.6 $8.6 $8.0 (7%) (6%) XOG $5.7 $5.3 $3.3 $5.8 76% 43% Median $5.7 $5.3 $5.6 $5.6 0% (19%) Sequential Change (17%) (8%) 6% 0% / Note: Companies report LOE differently. U.S. Independent E&Ps 50

51 Figure 76: Texas Well Completions (1 of 3) Week up to 11/18/2016 Operator 24 hr. IP Oil Test Completion Lateral IP - Boe/d % Oil Well Name County Test Date Field Basin / Sub-basin - bbl/d Date Length (ft). ANADARKO E&P % DOSEY DOE UNIT # 1H LOVING 10/25/ /31/2016 PHANTOM (WOLFCAMP) Delaware - Permian 6373 ft ANADARKO E&P % SEVENGILLS # 1H LOVING 10/12/ /21/2016 PHANTOM (WOLFCAMP) Delaware - Permian 3751 ft ANADARKO E&P % NANCY COUCH UNIT 3-15 # 1H REEVES 7/29/2016 7/31/2016 PHANTOM (WOLFCAMP) Delaware - Permian 8875 ft APACHE CORPORATION % MAGPIE UNIT #P111H LOVING 10/11/ /31/2016 PHANTOM (WOLFCAMP) Delaware - Permian 5932 ft ATLAS EAGLE % HARRIS #A 4H ATASCOSA 9/22/2016 9/27/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 6927 ft ATLAS EAGLE % MGS UNIT #B 1H ATASCOSA 10/10/ /13/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 6879 ft ATLAS EAGLE % MGS UNIT #B 2H ATASCOSA 10/10/ /12/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 7040 ft BP AMERICA % HILL, PERCY E #4648H LIPSCOMB 5/26/2016 6/21/2016 KIOWA CREEK (MARMATON) Granite Wash 5144 ft BURLINGTON RESOURCES % LEO FRANK UNIT B #2 KARNES 9/7/2016 9/22/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 4705 ft CARRIZO (EAGLE % MILLETT A UNIT # 21H LA SALLE 9/7/ /29/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 5659 ft CARRIZO (EAGLE % MILLETT B UNIT # 22H LA SALLE 9/8/ /21/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 4782 ft CARRIZO (EAGLE % PENA # 43H LA SALLE 8/19/2016 9/27/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 5268 ft CHESAPEAKE OPERATING, % LAZY A COTULLA UNIT DIM #H 2H DIMMIT 9/17/2016 9/19/2016 BRISCOE RANCH (EAGLEFORD) Eagle Ford ft CHESAPEAKE OPERATING, % LAZY A COTULLA UNIT DIM #H 4H DIMMIT 9/18/2016 9/29/2016 BRISCOE RANCH (EAGLEFORD) Eagle Ford ft CHESAPEAKE OPERATING, % LAZY A COTULLA UNIT DIM #H 3H DIMMIT 9/19/2016 9/25/2016 BRISCOE RANCH (EAGLEFORD) Eagle Ford ft CHESAPEAKE OPERATING, % LAZY A COTULLA #G 4H DIMMIT 8/30/2016 9/9/2016 BRISCOE RANCH (EAGLEFORD) Eagle Ford ft CHESAPEAKE OPERATING, % LAZY A COTULLA #H 1H DIMMIT 9/18/ /2/2016 BRISCOE RANCH (EAGLEFORD) Eagle Ford 4003 ft CHESAPEAKE OPERATING, % LAZY A COTULLA #H 5H DIMMIT 9/19/ /2/2016 BRISCOE RANCH (EAGLEFORD) Eagle Ford ft CHESAPEAKE OPERATING, % PEELER MCM #O 1H MCMULLEN 9/13/2016 9/14/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 6241 ft CHESAPEAKE OPERATING, % PEELER MCM #O 2H MCMULLEN 9/13/2016 9/17/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 6204 ft CHESAPEAKE OPERATING, % PEELER MCM #O 4H MCMULLEN 9/13/2016 9/14/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 6115 ft CHESAPEAKE OPERATING, % PEELER MCM #O 5H MCMULLEN 9/12/2016 9/15/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 6165 ft CHESAPEAKE OPERATING, % PEELER MCM #O 6H MCMULLEN 9/12/2016 9/13/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 6087 ft CHESAPEAKE OPERATING, % JJ HENRY UNIT VI #J 2H MCMULLEN 9/16/2016 9/22/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 7418 ft CHESAPEAKE OPERATING, % JJ HENRY UNIT VI #J 3H MCMULLEN 9/16/2016 9/22/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 7376 ft CHESAPEAKE OPERATING, % JJ HENRY UNIT VI #J 4H MCMULLEN 9/18/2016 9/24/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 7147 ft DIAMONDBACK E&P % PHILLIPS-HODNETT UNIT # 1LS HOWARD 6/22/2016 8/28/2016 SPRABERRY (TREND AREA) Midland - Permian 7296 ft DIAMONDBACK E&P % PHILLIPS-HODNETT UNIT # 1WA HOWARD 6/15/2016 7/15/2016 SPRABERRY (TREND AREA) Midland - Permian 7430 ft DISCOVERY OPERATING, % GERONIMO (SA) C #2703LS MIDLAND 9/11/ /28/2016 SPRABERRY (TREND AREA) Midland - Permian 7788 ft ELK RIVER % WAPITI # 4H ANDREWS 7/15/2016 8/3/2016 THREE BAR (WICHITA) Central Basin - Permian 7097 ft Source: Texas RRC

52 Figure 77: Texas Well Completions (2 of 3) Week up to 11/18/2016 Operator 24 hr. IP Oil Test Completion Lateral IP - Boe/d % Oil Well Name County Test Date Field Basin / Sub-basin - bbl/d Date Length (ft). ENCANA OIL % HONS UNIT # 19H KARNES 8/17/ /5/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 4367 ft ENCANA OIL % HOFFMANN UNIT # 17H KARNES 8/17/ /5/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 4557 ft ENERGEN RESOURCES % JONES-HOLTON # 509H MARTIN 4/27/2016 5/15/2016 SPRABERRY (TREND AREA) Midland - Permian 6667 ft ENERGEN RESOURCES % JONES-HOLTON # 506H MARTIN 4/25/2016 6/10/2016 SPRABERRY (TREND AREA) Midland - Permian 7041 ft ENERGEN RESOURCES % JONES-HOLTON # 507H MARTIN 4/28/2016 5/1/2016 SPRABERRY (TREND AREA) Midland - Permian 7010 ft ENERGEN RESOURCES % JONES-HOLTON # 510H MARTIN 5/23/2016 7/17/2016 SPRABERRY (TREND AREA) Midland - Permian 7106 ft ENERGEN RESOURCES % JONES-HOLTON # 210H MARTIN 5/9/2016 6/24/2016 SPRABERRY (TREND AREA) Midland - Permian 7120 ft ENERVEST OPERATING, % PAWLIK-RODRIGUEZ UNIT # 1H ATASCOSA 9/9/2016 9/15/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 5309 ft ENERVEST OPERATING, % JANECKA # 1H FAYETTE 11/4/ /7/2014 CANNON (NAVARRO) Eagle Ford 6006 ft EOG RESOURCES, % STATE PATHFINDER # 17H LOVING 3/7/2016 3/11/2016 SANDBAR (BONE SPRING) Delaware - Permian 4840 ft EOG RESOURCES, % JAVELINA UNIT # 2H ATASCOSA 10/13/ /14/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 7532 ft EOG RESOURCES, % SPAHN FARMS UNIT # 8H GONZALES 10/27/ /3/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 5687 ft EOG RESOURCES, % SPAHN FARMS UNIT # 9H GONZALES 10/27/ /31/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 5822 ft EOG RESOURCES, % SPAHN FARMS UNIT # 10H GONZALES 10/27/ /3/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 5865 ft EOG RESOURCES, % SPRADLIN UNIT # 2H GONZALES 10/17/ /18/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 4502 ft EOG RESOURCES, % SPRADLIN UNIT # 3H GONZALES 10/17/ /18/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 4519 ft EOG RESOURCES, % SPRADLIN UNIT # 4H GONZALES 10/17/ /18/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 4376 ft EOG RESOURCES, % FUJI UNIT # 101H KARNES 9/1/2016 9/7/2016 SUGARKANE (AUSTIN CHALK) Eagle Ford 6488 ft EOG RESOURCES, % URBANCZYK UNIT # 7H KARNES 10/25/ /28/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 3954 ft EOG RESOURCES, % URBANCZYK UNIT # 9H KARNES 10/25/ /27/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 4018 ft EOG RESOURCES, % NAYLOR JONES UNIT 87 # 101H LA SALLE 6/26/2016 7/5/2016 SUGARKANE (AUSTIN CHALK) Eagle Ford 6610 ft HUNT OIL % BOONE-COFFEE (PSA) # 7HA GLASSCOCK 10/4/ /21/2016 SPRABERRY (TREND AREA) Midland - Permian 7517 ft KINDER MORGAN % YATES FIELD UNIT #275F41 PECOS 10/31/ /8/2016 YATES Delaware - Permian 996 ft KINDER MORGAN % YATES FIELD UNIT # 13Z06 PECOS 10/30/ /31/2016 YATES Delaware - Permian 1206 ft LAREDO PETROLEUM, % FRYSAK A (ALLOC-D) # 4SU GLASSCOCK 6/25/2016 7/17/2016 SPRABERRY (TREND AREA) Midland - Permian 9757 ft LAREDO PETROLEUM, % HOLT C (ALLOC-H) # 8SM REAGAN 4/20/2016 6/13/2016 SPRABERRY (TREND AREA) Midland - Permian 9937 ft LONE STAR % HAPGOOD RANCH # 6H CLAY 12/23/2015 3/18/2016 NEWARK, EAST (BARNETT SHALE) #N/A 4681 ft MANTI TARKA % ASSAULT 126 # 1HA WARD 7/6/2016 8/5/2016 PHANTOM (WOLFCAMP) Delaware - Permian 4804 ft Source: Texas RRC

53 Figure 78: Texas Well Completions (3 of 3) Week up to 11/18/2016 Operator 24 hr. IP Oil Test Completion Lateral IP - Boe/d % Oil Well Name County Test Date Field Basin / Sub-basin - bbl/d Date Length (ft). MARATHON OIL % TURNBULL UNIT D # 15H KARNES 8/15/2016 8/17/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 8358 ft MARATHON OIL % TURNBULL UNIT D # 16H KARNES 8/15/2016 8/18/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 5502 ft MARATHON OIL % TURNBULL UNIT D # 502H KARNES 8/15/2016 8/18/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 5231 ft MARATHON OIL % TURNBULL UNIT D # 501H KARNES 8/15/2016 8/17/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 5348 ft MARATHON OIL % RIPPSTEIN-GOTTHARDT UNIT # 502H KARNES 9/6/2016 9/9/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 5330 ft MARATHON OIL % RIPPSTEIN-GOTTHARDT UNIT # 504H KARNES 9/5/2016 9/9/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 4481 ft MATADOR PRODUCTION % DICK JAY 92-TTT-B01 WF # 124H LOVING 3/16/2016 4/22/2016 TWO GEORGES (BONE SPRING) Delaware - Permian 4822 ft MATADOR PRODUCTION % DICK JAY 92-TTT-B01 WF # 203H LOVING 4/5/2016 4/15/2016 PHANTOM (WOLFCAMP) Delaware - Permian 4798 ft MATADOR PRODUCTION % DICK JAY 92-TTT-B01 WF # 212H LOVING 4/6/2016 4/22/2016 PHANTOM (WOLFCAMP) Delaware - Permian 4742 ft MURPHY EXPL % JANYSEK UNIT A # 1H KARNES 9/17/ /4/2016 SUGARKANE (AUSTIN CHALK) Eagle Ford 5577 ft MURPHY EXPL % JANYSEK UNIT # 12H KARNES 9/2/2016 9/30/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 5492 ft PARSLEY ENERGY % PETTIT '8A-8' #4401H REAGAN 3/18/2016 4/1/2016 SPRABERRY (TREND AREA) Midland - Permian 5049 ft PARSLEY ENERGY % ZAIN 26 #4214H UPTON 7/20/2016 7/28/2016 SPRABERRY (TREND AREA) R 40 EXC Midland - Permian 5086 ft PARSLEY ENERGY % ZAIN 26 #4415H UPTON 7/20/2016 7/30/2016 SPRABERRY (TREND AREA) R 40 EXC Midland - Permian 5104 ft PIONEER NATURAL % MCCLINTIC 10G # 7H MIDLAND 8/11/2016 8/18/2016 SPRABERRY (TREND AREA) Midland - Permian 5553 ft PIONEER NATURAL % TEXAS TEN Y PU #3901H MIDLAND 6/6/2016 7/12/2016 SPRABERRY (TREND AREA) Midland - Permian 9753 ft PIONEER NATURAL % SHACKELFORD #3403H MIDLAND 7/20/2016 7/25/2016 SPRABERRY (TREND AREA) R 40 EXC Midland - Permian 9902 ft PMO % BELMONT STAKES # 1H BURLESON 9/26/ /4/2016 AGUILA VADO (EAGLEFORD) Woodbine/ Buda/ East TX - Eagle Ford 5831 ft RESOLUTE NATURAL % SOUTH MITRE 2 UNIT #2102H REEVES 10/3/ /4/2016 PHANTOM (WOLFCAMP) Delaware - Permian 9155 ft SEA EAGLE % PEELER RANCH EFS # 10HA ATASCOSA 9/17/ /27/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 6170 ft SEA EAGLE % HOSKINS EFS # 1H MCMULLEN 9/28/ /6/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 4800 ft SEA EAGLE % HOSKINS EFS # 3H MCMULLEN 9/28/ /6/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 5680 ft SEA EAGLE % TEAL RANCH EFS # 2H MCMULLEN 10/6/ /1/2016 EAGLEVILLE (EAGLE FORD-1) Eagle Ford 5407 ft SHELL WESTERN % UNIVERSITY 19 A #2303H LOVING 10/19/ /29/2016 PHANTOM (WOLFCAMP) Delaware - Permian 6015 ft SHELL WESTERN % GALAPAGOS LOV # 1H LOVING 10/2/ /10/2016 PHANTOM (WOLFCAMP) Delaware - Permian 4048 ft SN OPERATING, % PETRO PARDS # 5H ZAVALA 4/25/2016 5/2/2016 BRISCOE RANCH (EAGLEFORD) Eagle Ford 6497 ft SN OPERATING, % PETRO PARDS # 6H ZAVALA 4/25/2016 4/27/2016 BRISCOE RANCH (EAGLEFORD) Eagle Ford 6465 ft THOMPSON, J % BIG GEORGE 180 # 3H REEVES 6/4/2016 7/15/2016 WOLFBONE (TREND AREA) Delaware - Permian 7576 ft THOMPSON, J % AGATE 179NE # 1H REEVES 7/27/2016 9/9/2016 WOLFBONE (TREND AREA) Delaware - Permian 7976 ft TIDAL PETROLEUM, % JANYSEK # 1H KARNES 11/2/ /15/2016 EAGLEVILLE (EAGLE FORD-2) Eagle Ford 3055 ft U.S. ENERGY % IRONWOOD A2 UNIT #A 2EF FRIO 4/29/2016 5/26/2016 BRISCOE RANCH (EAGLEFORD) Eagle Ford 6160 ft WILLIAMS, CLAYTON % GELTEMEYER 297 # 1H REEVES 9/5/2016 9/22/2016 HOEFS T-K (WOLFCAMP) Delaware - Permian 4737 ft WILLIAMS, CLAYTON % COLLIER # 1H REEVES 7/17/2016 7/25/2016 HOEFS T-K (WOLFCAMP) Delaware - Permian 6284 ft XTO ENERGY % LHS RANCH #1715AH UPTON 10/31/ /9/2016 SPRABERRY (TREND AREA) R 40 EXC Midland - Permian 9604 ft Source: Texas RRC

54 U.S. Independent E&Ps 54 Appendix: Other Useful Statistics Figure 79: CS Coverage Comp Sheet (As of 11/18/2016) Summary Valuation Table P riced as o f % P rice P ro ven EV/ EB IT D A EV/ EV/ EV/ % o f P ro ved R eserves P / E P / C F P S 11/ 18/ 2016 Stock Target Upside P erformance Dividend M rkt Enterprise Reserves Reserve X Reserves Flowing P V-10 Name Ticker Rating P rice P rice to TP YTD YoY Yield Cap Value (M M Boe U.S. Gas PD Life 16E 17E 16E 17E 16E 17E ($ / boe) ($ / boe) (YE15) UN IVER SE Anadarko Petroleum Corp. APC OUTPERFORM $61.45 $77 25% 26% 1% 0.33% $31,217 $45,996 2,057 90% 49% 79% 6.7 NM NM 11.4x 6.2x 11.6x 6.5x $22.37 $ x Antero Resources AR OUTPERFORM $24.60 $38 54% 13% 6% NA $6,742 $11,427 2, % 72% 44% x 59.6x 6.1x 6.1x 9.5x 9.3x $5.19 $ x Apache Corp. APA NEUTRAL $61.40 $77 25% 38% 24% 1.63% $23,194 $30,504 1,564 54% 37% 59% 7.8 NM 66.1x 10.3x 6.7x 10.1x 6.7x $19.51 $ x Carrizo Oil & Gas Inc. CRZO NEUTRAL $36.26 $41 13% 23% -7% NA $1,887 $3, % 24% 45% x 26.9x 7.3x 6.4x 9.2x 8.1x $18.17 $ x Chesapeake Energy Corp. CHK NEUTRAL $5.89 $7 19% 31% 0% 0.00% $4,575 $20,104 1, % 67% 84% 6.1 NM 13.7x 6.3x 3.4x 13.0x 8.5x $13.37 $ x Continental Resources Inc. CLR NEUTRAL $49.63 $50 1% 116% 44% NA $18,356 $25,462 1, % 43% 43% 15.2 NM 63.8x 14.8x 7.9x 14.8x 9.4x $20.77 $ x Callon Petroleum Co. CPE OUTPERFORM $14.38 $19 32% 72% 58% NA $945 $1, % 20% 53% x 23.1x 7.5x 9.4x 12.6x 9.5x $22.70 $ x Concho Resources Inc. CXO OUTPERFORM $ $160 23% 40% 20% NA $15,740 $18, % 41% 57% x NM 12.4x 12.1x 12.5x 12.2x $30.22 $ x ConocoPhillips COP NEUTRAL $43.61 $53 22% -7% -19% 2.29% $54,211 $76,723 8,180 39% 35% 63% 14.1 NM NM 12.7x 7.0x 12.6x 8.1x $9.38 $ x Denbury Resources Inc. DNR UNDERPERFORM $3.00 $2-33% 49% -17% 0.00% $1,049 $4, % 2% 79% 10.9 NM 123.9x 4.9x 3.5x 12.0x 9.4x $14.98 $ x Devon Energy Corp. DVN OUTPERFORM $42.87 $55 28% 34% -7% 0.56% $17,737 $28,540 2,182 75% 44% 83% 8.8 NM 41.9x 7.3x 7.6x 12.5x 7.7x $13.08 $ x Diamondback Energy Inc. FANG OUTPERFORM $97.92 $120 23% 46% 23% NA $6,174 $6, % 16% 59% x 34.5x 23.0x 12.9x 22.4x 12.4x $42.38 $ x Energen Corp. EGN OUTPERFORM $56.39 $70 24% 38% -3% 0.00% $4,283 $5, % 20% 52% 14.8 NM 238.9x 22.3x 10.3x 19.2x 10.5x $14.26 $ x EOG Resources Inc. EOG NEUTRAL $92.34 $96 4% 30% 11% 0.73% $50,670 $56,612 2,118 97% 30% 51% 10.1 NM 133.6x 20.7x 10.7x 22.8x 11.5x $26.73 $ x EP Energy EPE NEUTRAL $4.17 $4-4% -5% -30% NA $1,019 $5, % 29% 47% x NM 1.4x 2.7x 5.2x 7.9x $9.37 $ x EQT Corporation EQT OUTPERFORM $66.90 $86 29% 28% 10% 0.18% $10,234 $11,426 1, % 91% 63% 16.5 NM 109.5x 15.8x 9.7x 10.0x 7.5x $6.87 $ x Gulfport Energy Corp. GPOR OUTPERFORM $24.45 $37 51% 0% -15% NA $2,443 $3, % 91% 45% x 23.9x 7.9x 6.1x 8.7x 7.0x $11.53 $ x Hess Corp. HES NEUTRAL $50.50 $65 29% 4% -16% 1.98% $14,323 $18,237 1,086 46% 24% 73% 7.9 NM NM 24.9x 8.6x 14.8x 9.1x $16.79 $ x Laredo Petroleum Inc. LPI UNDERPERFORM $14.03 $10-29% 76% 15% NA $2,792 $4, % 29% 80% x 44.3x 9.8x 10.6x 10.3x 11.4x $33.23 $ x Marathon Oil Corp. MRO NEUTRAL $15.46 $20 29% 23% -13% 1.29% $10,470 $16,526 2,163 44% 19% 72% 13.8 NM NM 14.2x 5.9x 12.5x 7.1x $7.64 $ x Murphy Oil Corp. MUR NEUTRAL $30.30 $33 9% 35% 1% 3.30% $5,322 $8, % 36% 62% 10.2 NM 352.8x 7.1x 4.5x 8.2x 5.3x $10.46 $ x Newfield Exploration Co. NFX OUTPERFORM $39.80 $53 33% 22% -1% NA $6,318 $8, % 43% 65% x 18.9x 9.7x 7.9x 10.3x 9.0x $17.27 $ x Noble Energy Inc. NBL OUTPERFORM $35.34 $ % 7% -3% 1.13% $14,233 $21,181 1,421 62% 65% 66% 11.0 NM NM 8.7x 6.9x 8.6x 7.8x $14.91 $ x Oasis Petroleum Inc. OAS NEUTRAL $12.04 $ % 63% 2% NA $1,566 $3, % 15% 68% 11.8 NM NM 6.4x 4.0x 9.9x 7.6x $17.68 $ x Occidental Petroleum Corp. OXY NEUTRAL $67.81 $67-1% 0% -9% 4.48% $51,920 $55,859 2,200 58% 26% 79% 9.1 NM 107.7x 13.9x 10.0x 18.1x 10.0x $25.39 $ x PDC Energy Inc PDCE OUTPERFORM $65.94 $79 20% 24% 12% NA $2,611 $3, % 40% 26% 17.8 NM NM 7.1x 7.7x 7.8x 8.1x $11.92 $ x Parsley Energy PE OUTPERFORM $34.16 $42 23% 85% 81% NA $4,619 $4, % 21% 42% x 60.9x 23.5x 12.8x 21.5x 12.3x $39.02 $ x Pioneer Natural Resources PXD OUTPERFORM $ $216 23% 40% 24% 0.05% $26,246 $28, % 34% 89% 8.9 NM 134.8x 17.3x 12.2x 16.1x 12.1x $42.24 $ x Range Resources Corp. RRC OUTPERFORM $34.03 $46 35% 38% 3% 0.24% $5,664 $8,315 1, % 63% 55% 19.4 NM 52.8x 11.9x 8.3x 14.6x 9.9x $5.04 $ x Sanchez Energy Corp SN NEUTRAL $6.85 $ % 59% 27% NA $392 $1, % 31% 51% x NM 2.5x 3.4x 5.6x 7.2x $13.35 $ x Southwestern Energy Co. SWN NEUTRAL $10.37 $13 25% 46% -5% NA $3,946 $8,660 1, % 95% 93% 6.4 NM 15.4x 9.0x 4.9x 12.1x 7.4x $8.36 $ x Synergy Resources SYRG OUTPERFORM $8.16 $9 10% -4% -29% NA $775 $ % 51% 27% 16.6 NM 36.6x 31.2x 10.8x 27.4x 11.6x $12.69 $ x Whiting Petroleum Corp. WLL OUTPERFORM $9.13 $12 31% -3% -46% NA $1,784 $6, % 14% 49% 13.8 NM NM 4.3x 4.6x 9.1x 8.5x $8.49 $ x Extraction Oil & Gas XOG OUTPERFORM $21.33 $30 41% #N/A NA NA $5,915 $6, % 31% 19% 22.4 NM 233.2x 24.4x 8.1x 18.2x 7.9x $40.69 $ x UNIVERSE M EDIAN 23% 31% 1% 0.64% 100% 35% 59% x 56.2x 9.8x 7.6x 12.1x 8.5x $ #### 3.2x UNIVERSE M EAN 19% 33% 4% 1.14% 88% 40% 61% x 81.1x 11.9x 7.6x 12.9x 9.0x $ #### 3.9x UNIVERSE WEIGHTED M EAN 18% 26% 4% 1.32% 77% 40% 66% x 98.5x ### 8.6x 14.0x 9.0x $ $ x Source: Thomson Reuters Datastream, Company data, Credit Suisse estimates

55 Figure 80: 2016 and 2017 Revenue per boe 2016 Rev/boe 2017 Rev/boe 2016 Median 2017 Median $50 $45 $40 $35 $30 $25 $20 $15 $10 $5 $0 Note: Estimates assume $42.18/bbl crude oil and $2.45/MMbtu gas in 2016 and $55.00/bbl crude and $3.25/MMbtu gas in Figure 81: 2016 and 2017 EBITDAX per boe $ EBITDAX/boe 2017 EBITDAX/boe 2016 Median 2017 Median $30 $25 $20 $15 $10 $5 $0 Note: Estimates assume $42.18/bbl crude oil and $2.45/MMbtu gas in 2016 and $55.00/bbl crude and $3.25/MMbtu gas in U.S. Independent E&Ps 55

56 Figure 82: 2017 EBITDAX/boe vs. % oil (at Credit Suisse deck) $35 EBITDAX/boe $30 $25 $20 $15 CHK NBL SN NFX LPI APA HES CVX PXD CXO CRZO EOG EPE MUR OXY EGN XOG DVN PDCE APC SYRG COP XOM CLR MRO CPE PE FANG WLL OAS DNR $10 AR GPOR RRC SWN EQT $5 $0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% % Oil *Note MRO and OXY include international gas U.S. Independent E&Ps 56

57 Figure 83: Total Oil Production (Mbbl/d) 3Q16/2Q16 3Q16/3Q15 4Q15 1Q16 2Q16 3Q16 QoQ YoY FY15 FY16 YoY FY17 FY18 Majors COP % 4.2% (0.2%) CVX 1, , , ,661.0 (1.7%) (1.0%) 1, ,721.2 (1.3%) 1, ,844.1 XOM 2, , , ,211.0 (5.1%) (5.1%) 2, , % 2, ,537.4 OXY (5.4%) (14.9%) (8.3%) Sub-Total 5, , , ,170.0 (2.6%) (3.1%) 5, ,392.8 (0.7%) 5, ,764.4 Sequential Change 4.9% 1.2% (6.3%) (2.6%) 6.7% (0.7%) 3.6% 3.2% Large Cap E&P APA (8.1%) (23.6%) (20.9%) APC % 5.3% (2.3%) AR (12.2%) (35.9%) (14.3%) CHK (4.3%) (24.1%) (19.3%) CLR (12.6%) (21.2%) (10.3%) CXO % (6.3%) (2.1%) DVN (3.1%) (11.0%) (5.9%) EOG % 1.1% (1.5%) HES % (22.1%) (21.1%) MRO % (13.6%) (13.2%) MUR (0.4%) (20.4%) (18.0%) NBL (0.8%) 9.8% % PXD (0.4%) 23.0% % Sub-Total 2, , , , % (9.7%) 2, ,219.0 (8.3%) 2, ,820.9 Sequential Change (2.0%) (2.6%) (5.6%) 0.3% 7.1% (8.3%) 11.7% 13.8% SMID Cap E&P CPE % 67.3% % CRZO % 3.9% % DNR (3.0%) (11.5%) (10.9%) EGN (1.8%) (8.7%) (8.9%) EPE (0.2%) (27.5%) (23.4%) EQT (6.1%) 2.2% (1.0%) FANG % 30.7% % GPOR (6.5%) (28.8%) (25.8%) LPI % 16.6% % NFX (6.9%) (4.5%) (3.2%) OAS (4.2%) (11.0%) (5.5%) PDCE % 16.5% % PE % 131.5% % RRC (5.6%) (15.4%) (13.6%) SN (5.5%) (6.5%) (11.3%) SWN (9.5%) (4.6%) (1.2%) SYRG % (19.5%) % WLL (12.0%) (33.7%) (28.3%) XOG % 27.1% % Sub-Total (3.4%) (10.2%) (6.1%) Sequential Change (0.5%) (2.5%) (4.2%) (3.4%) 27.9% (6.1%) 14.2% 18.2% Total E&P 8,556 8,546 8,035 7,886 (1.9%) (5.5%) 8,438 8,163 (3.3%) 8,693 9,329 Sequential Change 2.5% (0.1%) (6.0%) (1.9%) 8.0% (3.3%) 6.5% 7.3% U.S. Independent E&Ps 57

58 Figure 84: Oil Growth % 3Q16/3Q15 3Q15 4Q15 1Q16 2Q16 3Q16 YoY Majors COP (1.8%) 3.6% 0.8% (3.4%) 3.3% 4.2% CVX (2.6%) 5.8% 0.3% (5.2%) (1.7%) (1.0%) XOM 1.7% 6.4% 2.3% (8.2%) (5.1%) (5.1%) OXY 0.7% (3.7%) (0.7%) (6.0%) (5.4%) (14.9%) Median (0.5%) 4.7% 0.5% (5.6%) (3.4%) (3.1%) Large Cap E&P APA (5.6%) (10.9%) (2.6%) (4.2%) (8.1%) (23.6%) APC (5.3%) 5.0% (0.3%) (6.0%) 7.1% 5.3% AR 25.0% (19.9%) (9.8%) 1.1% (12.2%) (35.9%) CHK (3.8%) (14.3%) (2.2%) (5.4%) (4.3%) (24.1%) CLR (1.6%) (1.3%) 0.6% (9.2%) (12.6%) (21.2%) CXO (2.0%) (5.9%) (2.7%) 0.5% 1.9% (6.3%) DVN 4.4% (1.4%) 2.5% (9.1%) (3.1%) (11.0%) EOG 0.7% 0.5% (4.7%) (0.1%) 5.6% 1.1% HES (0.8%) (4.5%) (10.7%) (13.9%) 6.1% (22.1%) MRO 10.0% (5.2%) (8.6%) (3.7%) 3.5% (13.6%) MUR 4.0% (5.5%) 2.7% (17.7%) (0.4%) (20.4%) NBL 15.5% 23.2% (5.8%) (4.6%) (0.8%) 9.8% PXD 8.5% 3.5% 8.7% 9.7% (0.4%) 23.0% Median 0.7% (4.5%) (2.6%) (4.6%) (0.4%) (13.6%) SMID Cap E&P CPE (0.5%) 12.8% 16.1% 6.3% 20.3% 67.3% CRZO 5.8% 5.8% 3.5% (7.2%) 2.3% 3.9% DNR (2.8%) 0.7% (3.3%) (6.3%) (3.0%) (11.5%) EGN (0.6%) (0.7%) (11.5%) 5.8% (1.8%) (8.7%) EPE (2.1%) (9.0%) (10.1%) (11.2%) (0.2%) (27.5%) EQT (4.2%) 9.2% (15.5%) 17.9% (6.1%) 2.2% FANG 12.9% 15.0% 0.9% (8.2%) 22.7% 30.7% GPOR (0.4%) (7.9%) (9.8%) (8.5%) (6.5%) (28.8%) LPI (5.9%) (10.2%) 22.5% 0.3% 5.7% 16.6% NFX (8.0%) 4.5% 1.1% (2.9%) (6.9%) (4.5%) OAS 0.6% (2.3%) (1.8%) (3.2%) (4.2%) (11.0%) PDCE 25.6% 4.0% (7.6%) 4.4% 16.2% 16.5% PE (3.6%) 26.8% 19.7% 24.6% 22.4% 131.5% RRC (13.0%) (6.4%) (4.9%) 0.6% (5.6%) (15.4%) SN (13.8%) 7.3% (7.6%) (0.3%) (5.5%) (6.5%) SWN (5.6%) 1.2% 7.9% (3.5%) (9.5%) (4.6%) SYRG 43.0% (14.2%) (3.2%) (3.6%) 0.7% (19.5%) WLL (6.9%) (7.1%) (7.3%) (12.4%) (12.0%) (33.7%) XOG 12.3% 13.1% 10.9% 0.0% 1.3% 27.1% Median (2.4%) 1.0% (3.3%) (3.0%) (2.4%) (5.6%) U.S. Independent E&Ps 58

59 Figure 85: E US Onshore Oil Volumes (Mbbl/d) Full Year Volumes % Change Ticker: /15 17/16 17/15 18/15 CVX % 5.6% 7.5% 13.7% XOM % 9.4% 15.0% 23.3% COP (3.4%) (1.0%) (4.4%) (8.0%) EOG (2.8%) 17.1% 13.8% 39.5% MRO (19.0%) 4.1% (15.7%) 1.8% OXY (5.1%) 12.5% 6.7% 37.8% APC (6.7%) 6.9% (0.3%) 14.1% DVN (21.8%) (15.4%) (33.8%) (15.7%) HES (17.0%) (1.8%) (18.5%) (14.7%) CLR (10.3%) 14.9% 3.0% 18.2% WLL (28.3%) (7.0%) (33.2%) (26.9%) APA (16.1%) (3.5%) (19.1%) (9.7%) CHK (19.3%) 7.9% (12.9%) 1.8% PXD % 29.2% 63.5% 104.7% CXO (2.1%) 20.6% 18.1% 44.3% NBL % 7.2% 33.7% 47.5% MUR (21.7%) (3.0%) (24.1%) (10.2%) DNR (10.9%) (6.6%) (16.8%) (17.8%) EPE (23.4%) (3.9%) (26.4%) (23.6%) NFX (2.6%) 8.1% 5.2% 35.4% OAS (5.5%) 28.4% 21.3% 32.3% EGN (8.9%) 21.4% 10.6% 38.0% FANG % 30.1% 60.3% 106.7% CRZO % 21.8% 34.7% 54.9% LPI % 12.9% 23.4% 35.6% SN (11.3%) (4.3%) (15.1%) (6.6%) PDCE % 48.8% 86.6% 148.3% PE % 55.8% 207.3% 331.6% RRC (13.6%) 30.7% 12.9% 29.6% XOG % 111.7% 192.3% 289.5% GPOR (25.8%) (21.3%) (41.6%) (52.4%) CPE % 46.1% 128.6% 210.5% SWN (1.2%) (0.8%) (2.0%) 10.3% AR (14.3%) 2.2% (12.4%) 3.9% SYRG % 90.4% 95.8% 218.1% EQT (1.0%) (7.2%) (8.1%) (18.6%) Total (Mbbl/d): 3, , , ,618.0 (4.5%) 8.2% 3.4% 17.1% % Change YoY 11.0% (4.5%) 8.2% 13.3% U.S. Independent E&Ps 59

60 Figure 86: Total Gas Production (MMcf/d) 3Q16/2Q16 3Q16/3Q15 4Q15 1Q16 2Q16 3Q16 QoQ YoY FY15 FY16 YoY FY17 FY18 Majors COP 4, , , ,777.0 (3.0%) (5.2%) 4, ,842.5 (5.4%) 3, ,924.2 CVX 5, , , , % (1.0%) 5, , % 6, ,786.1 XOM 10, , , ,601.0 (1.6%) 0.8% 10, ,094.2 (4.1%) 9, ,616.8 OXY 1, , (17.2%) (14.2%) (3.6%) ,050.6 Sub-Total 21, , , ,379.0 (1.9%) (1.7%) 20, ,153.2 (3.3%) 20, ,377.7 Sequential Change 6.9% (0.7%) (5.5%) (1.9%) (2.8%) (3.3%) 2.1% 3.9% Large Cap E&P APA 1, , (3.2%) (19.6%) 1, (19.4%) 1, ,357.6 APC 2, , , ,003.0 (8.5%) (8.4%) 2, ,049.6 (12.3%) 1, ,788.5 AR 1, , , , % 16.3% 1, , % 1, ,015.5 CHK 2, , , ,914.0 (1.6%) 1.9% 2, ,845.5 (3.0%) 2, ,556.6 CLR % 13.3% % CXO % 18.6% % DVN 1, , , ,324.0 (13.3%) (16.5%) 1, ,410.1 (12.4%) 1, ,337.3 EOG 1, , , ,144.0 (4.2%) (10.2%) 1, ,183.2 (6.5%) 1, ,281.7 HES (12.4%) (17.8%) (9.4%) MRO % 3.2% (3.4%) MUR % (10.7%) (11.6%) NBL 1, , , , % 13.3% 1, , % 1, ,347.5 PXD (2.4%) (7.7%) (4.3%) Sub-Total 14, , , ,061.2 (2.6%) (2.8%) 14, ,083.7 (3.7%) 13, ,944.5 Sequential Change (0.9%) 2.3% (1.6%) (2.6%) (0.4%) (3.7%) (2.8%) 9.2% SMID Cap E&P CPE % 81.1% % CRZO (6.7%) 33.9% % DNR (3.0%) (29.4%) (28.2%) EGN % (22.6%) (37.1%) EPE (20.9%) (44.0%) (24.5%) EQT 1, , , , % 23.9% 1, , % 2, ,497.6 FANG % 26.0% % GPOR % 20.8% % ,221.0 LPI % 14.6% % NFX % 10.9% % OAS % 45.6% % PDCE % 46.7% % PE % 35.2% % RRC 1, , % (3.9%) , % 1, ,751.0 SN (9.7%) 5.0% % SWN 2, , , ,054.3 (7.9%) (17.1%) 2, ,157.2 (12.4%) 2, ,184.2 SYRG (6.3%) 31.0% % WLL (9.3%) 4.0% (0.7%) XOG % 74.1% % Sub-Total 6, , , ,891.3 (0.4%) 0.5% 6, , % 7, ,362.2 Sequential Change 1.3% 1.7% (2.0%) (0.4%) 23.9% 5.8% 12.0% 19.0% Total E&P 42,353 42,651 41,119 40,332 (1.9%) (1.7%) 42,100 41,264 (2.0%) 42,131 45,684 Sequential Change 3.2% 0.7% (3.6%) (1.9%) 1.5% (2.0%) 2.1% 8.4% U.S. Independent E&Ps 60

61 Figure 87: Total NGL Production (bbl/d) 3Q16/2Q16 3Q16/3Q15 4Q15 1Q16 2Q16 3Q16 QoQ YoY FY15 FY16 YoY FY17 FY18 FY16 Large Cap E&P % Total Production APA % 2.2% % % APC (1.5%) 5.7% (4.1%) % AR % 70.5% % % CHK (10.2%) (13.7%) (12.5%) % DVN (20.6%) (22.4%) (15.7%) % EOG (2.8%) 5.3% % % HES % 12.5% % % NBL (3.1%) 12.7% % % PXD % 18.3% % % Sub-Total (3.2%) 3.6% % Sequential Change 1.9% 2.7% 2.2% (3.2%) 26.6% 4.0% 0.9% 12.9% SMID Cap E&P CRZO (9.4%) 25.9% % % EGN % (9.3%) (14.3%) % EPE % (11.7%) (3.0%) % EQT % 43.0% % % FANG % 41.4% % % GPOR % (10.7%) (14.6%) % LPI % 10.6% % % NFX % 26.1% % % PDCE % 80.1% % % PE % 76.8% % % RRC (2.9%) 35.2% % % SN (8.1%) (6.4%) % % SWN (3.2%) 1.1% % % WLL (5.3%) 11.2% % % XOG % 55.7% % % Sub-Total % 20.1% % Sequential Change 1.7% 5.5% 6.3% 5.4% 56.5% 21.8% 14.0% 15.7% Total E&P (0.7%) 8.1% % 1,005 1,143 Sequential Change 1.9% 3.5% 3.4% (0.7%) 33.5% 8.8% 4.8% 13.8% U.S. Independent E&Ps 61

62 Figure 88: E Capex Estimates Capex ($MM) % Change Ticker: /15 17/16 17/15 18/15 COP $10,050 $5,199 $4,913 $5,084 (48.3%) (5.5%) (51.1%) (49.4%) APC $6,067 $3,394 $4,129 $4,597 (44.1%) 21.7% (31.9%) (24.2%) DVN $5,308 $2,136 $2,892 $3,345 (59.8%) 35.4% (45.5%) (37.0%) EOG $5,013 $2,800 $4,500 $6,000 (44.1%) 60.7% (10.2%) 19.7% APA $4,811 $2,030 $3,218 $3,998 (57.8%) 58.5% (33.1%) (16.9%) OXY $4,522 $3,171 $3,681 $4,632 (29.9%) 16.1% (18.6%) 2.4% HES $4,321 $2,339 $2,756 $3,342 (45.9%) 17.8% (36.2%) (22.6%) MRO $3,476 $1,432 $2,217 $2,769 (58.8%) 54.8% (36.2%) (20.3%) CHK $3,238 $1,750 $2,200 $2,700 (46.0%) 25.7% (32.1%) (16.6%) CLR $3,043 $1,098 $2,074 $2,472 (63.9%) 88.9% (31.8%) (18.7%) NBL $2,979 $1,450 $2,200 $2,700 (51.3%) 51.7% (26.1%) (9.4%) MUR $2,550 $626 $963 $1,297 (75.4%) 53.8% (62.2%) (49.1%) WLL $2,455 $550 $700 $1,050 (77.6%) 27.3% (71.5%) (57.2%) EQT $2,434 $1,490 $2,200 $2,615 (38.8%) 47.6% (9.6%) 7.4% AR $2,348 $1,880 $1,900 $2,300 (19.9%) 1.1% (19.1%) (2.0%) PXD $2,110 $2,100 $2,750 $3,200 (0.5%) 31.0% 30.3% 51.7% CXO $1,900 $1,300 $1,525 $1,975 (31.6%) 17.3% (19.7%) 3.9% SWN $1,798 $750 $1,050 $1,300 (58.3%) 40.0% (41.6%) (27.7%) NFX $1,607 $850 $1,000 $1,400 (47.1%) 17.6% (37.8%) (12.9%) GPOR $1,593 $525 $750 $950 (67.0%) 42.9% (52.9%) (40.4%) EPE $1,433 $490 $450 $550 (65.8%) (8.2%) (68.6%) (61.6%) EGN $1,154 $485 $800 $850 (58.0%) 64.9% (30.7%) (26.4%) RRC $1,035 $569 $920 $1,300 (45.0%) 61.7% (11.1%) 25.6% OAS $820 $400 $450 $550 (51.2%) 12.5% (45.1%) (32.9%) CRZO $676 $435 $375 $450 (35.6%) (13.8%) (44.5%) (33.4%) SN $656 $275 $300 $320 (58.1%) 9.1% (54.3%) (51.2%) PDCE $605 $450 $700 $950 (25.6%) 55.6% 15.8% 57.1% LPI $588 $420 $480 $470 (28.6%) 14.3% (18.4%) (20.1%) FANG $420 $425 $575 $ % 35.3% 37.1% 90.7% XOG $414 $380 $650 $750 (8.3%) 71.1% 56.9% 81.0% PE $383 $475 $650 $ % 36.8% 69.9% 109.1% SYRG $276 $145 $325 $400 (47.4%) 124.1% 17.8% 45.0% CPE $227 $150 $280 $350 (34.0%) 86.7% 23.2% 54.0% Total ($MM) $80,309 $41,970 $54,573 $66,266 (47.7%) 30.0% (32.0%) (17.5%) U.S. Independent E&Ps 62

63 Figure 89: E Cash Flow Estimates Cash Flow ($MM) % Change Ticker: /15 17/16 17/15 18/15 COP $7,572 $4,270 $7,675 $9,659 (43.6%) 79.7% 1.4% 27.6% DVN $5,383 $3,028 $2,959 $4,231 (43.7%) (2.3%) (45.0%) (21.4%) EOG $3,741 $2,470 $4,951 $7,288 (34.0%) 100.5% 32.4% 94.8% OXY $3,351 $3,736 $5,194 $6, % 39.0% 55.0% 90.0% APC $2,323 $2,802 $5,495 $7, % 96.1% 136.6% 205.3% CHK $2,268 $923 $1,723 $2,867 (59.3%) 86.7% (24.0%) 26.4% NBL $2,168 $1,753 $2,196 $2,917 (19.2%) 25.3% 1.3% 34.5% HES $1,981 $670 $1,888 $2,884 (66.2%) 182.0% (4.7%) 45.6% CLR $1,857 $1,238 $2,324 $3,143 (33.3%) 87.7% 25.1% 69.3% MRO $1,565 $892 $2,220 $3,159 (43.0%) 148.8% 41.8% 101.9% SWN $1,468 $609 $1,132 $1,508 (58.5%) 85.8% (22.9%) 2.7% EPE $1,331 $749 $379 $409 (43.7%) (49.4%) (71.5%) (69.3%) PXD $1,270 $1,690 $2,451 $3, % 45.0% 93.0% 183.8% EQT $1,217 $1,031 $1,510 $2,219 (15.3%) 46.5% 24.1% 82.4% NFX $1,171 $798 $1,004 $1,544 (31.9%) 25.9% (14.2%) 31.8% MUR $1,168 $730 $1,149 $1,603 (37.5%) 57.3% (1.7%) 37.2% WLL $1,020 $527 $726 $1,070 (48.3%) 37.8% (28.8%) 4.9% AR $976 $1,198 $1,265 $2, % 5.6% 29.6% 108.1% CXO $862 $1,426 $1,579 $2, % 10.7% 83.1% 156.7% APA $850 $2,269 $3,463 $4, % 52.6% 307.4% 416.9% EGN $715 $240 $536 $851 (66.5%) 123.5% (25.0%) 19.1% RRC $701 $541 $1,005 $1,552 (22.8%) 85.8% 43.4% 121.5% PDCE $421 $458 $562 $ % 22.6% 33.6% 111.8% FANG $419 $317 $593 $931 (24.2%) 87.1% 41.7% 122.2% CRZO $377 $301 $375 $551 (20.3%) 24.5% (0.7%) 46.1% OAS $360 $347 $695 $752 (3.4%) 99.9% 93.0% 109.0% LPI $358 $327 $325 $426 (8.7%) (0.4%) (9.1%) 19.0% GPOR $339 $379 $505 $ % 33.1% 49.1% 169.4% SN $272 $180 $134 $233 (33.9%) (25.7%) (50.9%) (14.3%) PE $172 $283 $564 $ % 99.6% 227.7% 469.2% XOG $167 $140 $422 $815 (16.3%) 202.6% 153.4% 389.2% SYRG $125 $45 $151 $319 (63.8%) 233.3% 20.8% 155.3% CPE $87 $249 $254 $ % 2.3% 192.9% 385.8% Total ($MM) $48,054 $36,616 $57,405 $79,840 (23.8%) 56.8% 19.5% 66.1% U.S. Independent E&Ps 63

64 U.S. Independent E&Ps 64 Figure 90: Leading Edge Completion Tracker Proppant Fluid Basin / Play Sub-Play Operator Lbs/ft bbls/ft Stage Spacing Well Spacing Perf Cluster Spacing Lateral Length Style Well Cost: Bakken MB / TFS EOG na na na 650' na 8,400' High Density Frac $4.8 Bakken MB / TFS1 OAS ' 704' na 10,000' Slickwater $6.1 Bakken MB / TFS1 OAS ' 704' na 10,000' High Volume Proppant $6.1 Bakken MB / TFS WLL 880 ~20 na 880' na 10,000' Slickwater $6.8 Delaware Avalon CXO 2,000 na na 660' na 5,000' na $2.5 Delaware WC A/B EGN 1,800-2, ' 880' 33' 7,500' na $6.5 Delaware WC A/B EGN 1,800-2, ' 880' 33' 10,000' na $7.6 Delaware WC A/B EGN 1,600-1, ' 880' 65 7,500' na $5.9 Delaware WC A/B EGN 1,600-1, ' 880' 65 10,000' na $6.9 Delaware Wolfcamp Combo EOG na na na 660' na 7,000' High Density Frac $7.8 Delaware Wolfcamp Oil EOG na na na 880' na 8,300' High Density Frac $8.0 Delaware 2nd BS EOG na na na 850' na 7,000' High Density Frac $7.3 Delaware Leonard / Avalon EOG na na na 660' na 6,800' High Density Frac $6.3 Delaware WC FANG 1,500-2,000 na na 880' na 9,500' Slickwater $5.5 Delaware Wolfcamp A NBL 1,800 na na na 40'-60' 4,000' Slickwater/ Hypergel na Delaware WC A / B / C PDCE 2,000 na na 440'-1,320' 100' 5,300' Slickwater + Linear gel $6.5 Delaware WC A PE 1,800-1,900 na 160'-170' 660' na 7,000' Slickwater $5.7 Delaware Lower & Upper WC XEC 2,400 ~45 na 660' na 10,000' na $ Delaware Lower & Upper WC XEC 1,640 na na 660' na 10,000' na $ DJ Niobrara / Codell BCEI 1,500 na na na na 4,000' Plug n perf DJ Niobrara / Codell CRZO na na na 300'-450' na 4,200' Slickwater $2.4 DJ Niobrara NBL 1,100-1, na na na 4,500' Slickwater $2.6 DJ Niobrara PDCE 1,100-1, na 660' na 4,200' Slickwater $2.5 Eagle Ford Lower EF CHK na na na na na 9,300' Switching to Slickwater $4.0 Eagle Ford Lower EF CRZO 1,500-1,600 na 233' 325'-500' na 6,250' Slickwater $4.2 Eagle Ford Lower EF EOG 2, na 320' na 5,300' na $4.5 Eagle Ford Lower EF EPE 2,000 na 200' 660' na 5,300' na $5.1 Eagle Ford Lower EF NBL 2,100 na na 500'-1,000' 20'-40' 5300' Slickwater na Eagle Ford Lower EF SN 1,600 na na 800' na 5,000' na $3.3 Haynesville CHK 3,000-5,000 na na na na 10,000' Switching to slickwater $9.1 Marcellus AR 1, ' 750' na 9,000' na $8.1 Marcellus NBL na na na na na 10,000' na na Marcellus Super Rich RRC 1, ' 1,000' na 6,500' na $5.9 Marcellus Wet RRC 1, ' 1,000' na 7,000' na $5.8 Marcellus Dry RRC 1, ' 1,000' na 7,000' na $5.2 Marcellus SWN 2,000 na na na na 6,500' na $6.5 Midland WC CPE 1,500-1,700 na 200' na na 7,500' Slickwater with a bit of gel $5.0 Midland Spraberry CPE 2,000 na 200' 406' na 7,500' Slickwater with a bit of gel $5.0 Midland WC CPE 1,959 na 209' na na 7,718' na na Midland WC / LSB CXO 1,800 na na 660' na 10,000' na na Midland WC / LSB CXO 2,300 na na 660' na 6,200' na na Midland WC / LSB / MSB / Jo Mill EGN 1,700-2, ' 660'-880' 30' 10,000' na $8.0 Midland WC EPE 2,000 na 185' 660' na 7,500' na $4.7 Midland LSB / WC FANG 1,600 na na 660' na 7,600' Slickwater $5.5 Midland Upper WC LPI 1,690 na na 660' na 10,000' Long reach slickwater $6.3 Midland Middle WC LPI 1,730 na na 660' na 10,000' Long reach slickwater $6.3 Midland Cline LPI 1,770 na na 660' na 10,000' Long reach slickwater $6.3 Midland WC / LSB PE 1,600-1,700 na na 660' na 7,000' Slickwater $4.8 Midland WC A / WC B / LSB PXD 1, ' 800'-1,120' 15' 9,000' Slickwater $7.0 STACK Meramec / Oswego CHK 2,300 na na na 20'-30' 8,000' Switching to slickwater $9.1 STACK DVN 2,000 na 150' na 20 10,000' Slickwater w/ diversion STACK Meramec NFX 2,400 na na 880'-1,050' 50' 10,000' na $6.8 Utica AR 1, ' 1,000' na 9,000' na $9.4 Utica CRZO na na na 800' na 8,000' Slickwater $8.6 Utica Dry GPOR 1,800 na na 1,000' na 8,000' na $9.0 Utica Condensate / Wet Gas PDCE na na 200' na na 8,000' Hybrid/slickwater $6.5

65 Rig Count Figure 91: Total US Rig Count by Basin As of 11/18/16 DJ-Niobrara (lhs) Eagle Ford (lhs) Haynesville (lhs) Marcellus (lhs) Permian (lhs) Utica (lhs) Williston (lhs) Total US (rhs) 11/18/2016: /21/2016: /20/2015: YoY Change: -33% -49% -18% -21% 2% -5% -46% -22% MoM Change 6% 15% 35% 0% 8% 27% 13% 6% Peak: Trough: Total US (rhs) Permian (lhs) Eagle Ford (lhs) Williston (lhs) Marcellus (lhs) Haynesville (lhs) DJ-Niobrara (lhs) Utica (lhs) 600 2, , , , /4/2011 4/4/2011 6/4/2011 8/4/ /4/ /4/2011 2/4/2012 4/4/2012 6/4/2012 8/4/ /4/ /4/2012 2/4/2013 4/4/2013 6/4/2013 8/4/ /4/ /4/2013 2/4/2014 4/4/2014 6/4/2014 8/4/ /4/ /4/2014 2/4/2015 4/4/2015 6/4/2015 8/4/ /4/ /4/2015 2/4/2016 4/4/2016 6/4/2016 8/4/ /4/2016 Source: Baker Hughes, Credit Suisse estimates U.S. Independent E&Ps 65

66 Figure 92: Weekly US Horizontal Rig Count (As of 11/18/2016) 1,600 1,400 1,200 1,000 Horizontal Rig count is now 470 as of 11/18/16, 6% higher MoM, 19% lower YoY, and 66% below the peak Source: Baker Hughes, Credit Suisse estimates Figure 93: US Weekly Natural Gas v. Oil Rig Count Natural Gas Rigs Oil Rigs 2,000 1,800 1,600 1,400 1,200 1, Gas Rig count is now 116 as of 11/18/16, 7% higher MoM, 40% lower YoY, and 93% off peak levels. Oil Rig count is now 471 as of 11/18/16, 6% higher MoM, 16% lower YoY, and 71% off peak levels. Source: Baker Hughes, Credit Suisse estimates U.S. Independent E&Ps 66