Oil & Gas E&P. Permian Takeaway Risks: What s Priced In? 4 June 2018 Americas/United States Equity Research Oil & Gas Exploration & Production

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1 Americas/United States Equity Research Oil & Gas Exploration & Production Research Analysts Betty Jiang, CFA William Featherston Chris Baker, CFA William Janela, CFA Michael Ziffer, CFA Christopher Zhang, CFA Oil & Gas E&P SECTOR REVIEW Permian Takeaway Risks: What s Priced In? Permian E&Ps underperformance has been largely driven by the cash flow impact of widening Midland basis, but stocks are starting to reflect operational risks. Since the end of March, Permian-focused E&Ps have lagged the XOP by ~21.7%, as wider than expected differentials have left Midland prices little changed amidst the broader oil rally. Baking in current strip prices for WTI, Midland & Waha basis spreads, we see Permian-focused E&Ps trading at 8.2x/6.6x/5.1x on EBITDX, and have compressed their relative valuation vs. the non-permian focused oily E&Ps by ~0.5x from 1.8x to a 1.3x premium on The premium has compressed an even greater ~1.1x to just 0.4x on 2020, signaling that the market is starting to discount not only the cash flow impact in , but also potential reductions in production growth profiles. Risks of activity reductions are not fully baked in & uncertainty remains high. As operators uniformly claim flow assurance, with the exception of E&Ps with firm transport or Gulf Coast linked firm sales agreements, it s difficult to assess whose growth trajectory could be most at risk. We see E&Ps with back-end weighted growth profiles having greater execution risk (XEC, EGN & CPE among SMID-cap E&Ps, and APC, NBL among Large-Caps). An economic case could also be made as typical pretax NPV/well could improve ~10% if deferred 9 months into a ($3)/Bbl vs. a ($20)/Bbl basis. In a material slowdown downside case, which assumes E&Ps defer completions to keep volumes flattish 3Q18 to 4Q19, valuation would expand by another ~1.1x on 2019 and ~0.5x on 2020 EV/EBITDX. To keep 2020 multiples unchanged, the slowdown scenario infer an average downside of ~14.0% from current levels (SM, LPI, CPE have the most downside), though avg. NAV impact is a much less ~4.8%. What needs to happen to alleviate Permian uncertainty? We see two paths: 1)The hard way is any disclosure of slowdown in completion activity, leading to negative estimate revisions which could happen closer to 2019 budget season; 2) The easier solution (albeit with a high level of market skepticism & would only be available to a limited # of companies) may be Gulf Coast linked marketing contracts, similar to the one PDCE announced, which would provide flow assurance and remove a draconian downside scenario that could impact development plans. We believe more E&Ps, FANG & CXO in particular, are evaluating these types of agreements. Stock thoughts. Given the juxtaposition of cash flow/operational risks in , and more attractive longer term value looking through to 2020 and P/NAV, we see the potential for a better buying opportunity later in the year for Permian E&Ps once there s more clarity around the impact of takeaway constraints & wide diffs on 2019 activity. In the interim, we continue to prefer E&Ps that are well positioned on Permian takeaway, such as PXD, WPX, and PE, and names outside the Permian, such as MRO, CLR, OAS and XOG. With this note we are lowering CFPS for the Permian E&Ps by ~2.7% and ~3.5% as we now forecast Midland differential to peak at $12/Bbl in 4Q18. We re also downgrading SM to Neutral, and lowering TPs for the Permian E&Ps by ~4%. 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 What risks have been priced into Permian stocks? Permian takeaway concerns have increased since early April as the Midland-MEH differential has widened to a peak of $20/Bbl currently. Given the uncertainty, Permianfocused E&Ps have underperformed the group while oil prices and XOP rallied, as widening basis has left Midland prices essentially flat over the past couple months. As all the Permian operators have provided promises of flow assurance through either firm transport agreements (FT) or firm sales agreements with 3 rd party markers, we ve seen questions from investors shifting from who s best/worst positioned? to what s baked in? We believe the underperformance is still largely reflecting the cash flow impact of widening basis, though Friday s move is starting to price-in accompanying execution risk to 2H18+ programs. Since the end of March, Permian-focused E&Ps have lagged the XOP by ~21.7%, down ~1.8% (mkt cap weighted) vs. XOP up 20.0%, large-cap E&Ps +20.1% and ex. Permian-focused Oily E&P +28.4%. Baking in current strip prices for WTI, Midland and Waha basis spreads, we see Permian-focused E&Ps currently trading at 8.2x and 6.6x 2018/2019 EBITDX, up ~0.2 turn for both years since end of March before Permian differential concerns gained traction. Compared to the non- Permian focused oily E&P average, today s relative valuation on 2019 EV/EBITDX has compressed by ~0.5x from 1.8x to a 1.3x premium, however 2020 EV/EBITDX has narrowed by an even greater ~1.1x to just a 0.4x premium signaling that the market is starting to discount not only the cash flow impact in , but also potential changes in production growth profiles. Figure 1: Valuation impact of change in WTI and basis strip Since end of March 2018 % As of Mar 29, 2018 Current + Midland/Waha Strip Absolute Change Absolute Ticker 3/29/18 6/1/18 Change 2018E 2019E 2020E 2018E 2019E 2020E 2018E 2019E 2020E 3/29/18 6/1/18 Change Permian-Focused E&Ps CPE $13.24 $ % 8.0x 6.3x 5.6x 8.0x 6.4x 4.8x -0.0x +0.1x -0.7x 0.94x 0.67x -0.27x CDEV $18.35 $ % 7.7x 6.6x 5.7x 7.9x 7.0x 5.0x +0.2x +0.4x -0.6x 0.82x 0.70x -0.12x XEC $93.50 $ % 6.1x 5.4x 4.8x 6.8x 5.8x 4.7x +0.7x +0.4x -0.2x 0.76x 0.73x -0.03x CXO $ $ % 11.9x 8.3x 6.6x 10.5x 7.8x 5.4x -1.4x -0.5x -1.2x 1.05x 0.84x -0.21x FANG $ $ % 9.4x 6.9x 5.8x 10.0x 7.2x 5.1x +0.6x +0.3x -0.8x 0.95x 0.80x -0.15x EGN $62.86 $ % 6.7x 5.5x 4.7x 7.8x 6.2x 4.5x +1.1x +0.7x -0.2x 0.91x 0.83x -0.08x JAG $14.13 $ % 8.2x 6.7x 6.0x 7.5x 6.2x 4.6x -0.7x -0.5x -1.3x 0.98x 0.67x -0.31x LPI $8.71 $ % 4.6x 4.2x 4.1x 5.1x 4.7x 4.1x +0.5x +0.5x -0.0x 0.69x 0.71x +0.02x PE $28.99 $ % 8.6x 6.8x 6.0x 8.3x 6.9x 5.7x -0.2x +0.1x -0.3x 0.77x 0.68x -0.10x PXD $ $ % 8.8x 7.5x 6.8x 9.9x 7.8x 6.6x +1.1x +0.3x -0.2x 0.61x 0.57x -0.04x Permian-Focused Average -1.8% 8.0x 6.4x 5.6x 8.2x 6.6x 5.0x +0.2x +0.2x -0.6x 0.85x 0.72x -0.13x Non Permian-Focused Oily E&Ps NFX $24.42 $ % 5.5x 4.7x 4.6x 6.1x 5.0x 4.7x +0.6x +0.3x +0.1x 0.64x 0.81x +0.17x PDCE $49.03 $ % 5.0x 3.9x 3.4x 5.6x 4.6x 4.0x +0.6x +0.7x +0.5x 0.84x 0.95x +0.11x QEP $9.79 $ % 6.0x 5.4x 5.0x 6.4x 6.2x 5.4x +0.5x +0.8x +0.4x 0.80x 0.89x +0.09x SM $18.03 $ % 5.7x 4.1x 3.8x 6.7x 5.0x 4.0x +1.1x +0.9x +0.2x 0.53x 0.67x +0.14x WPX $14.78 $ % 7.3x 5.7x 5.2x 9.6x 6.5x 5.5x +2.3x +0.8x +0.4x 0.70x 0.78x +0.08x CLR $58.95 $ % 7.4x 6.4x 5.5x 7.8x 6.6x 5.9x +0.5x +0.2x +0.3x 1.04x 1.08x +0.03x OAS $8.10 $ % 4.8x 4.0x 3.5x 6.4x 5.3x 4.7x +1.6x +1.4x +1.2x 0.50x 0.75x +0.25x WLL $33.84 $ % 4.7x 4.0x 3.7x 5.7x 4.5x 4.2x +1.1x +0.5x +0.6x 0.81x 1.04x +0.23x XOG $11.46 $ % 4.1x 3.1x 2.7x 5.5x 3.9x 3.4x +1.4x +0.8x +0.7x 0.36x 0.69x +0.34x SRCI $9.43 $ % 5.4x 4.3x 3.7x 6.9x 5.2x 4.5x +1.5x +0.9x +0.9x 1.05x 0.96x -0.08x Ex. Permian-Focused Oily Avg. 27.8% 5.6x 4.6x 4.1x 6.7x 5.3x 4.6x +1.1x +0.7x +0.5x 0.73x 0.86x +0.14x Large-Cap E&Ps Stock Price EV / EBITDX (Strip Price Deck) Price / 2P NAV APC $60.41 $ % 5.3x 4.6x 4.3x 6.0x 5.0x 4.5x +0.7x +0.3x +0.2x 0.65x 0.75x +0.10x APA $38.48 $ % 4.8x 5.0x 5.0x 4.7x 4.6x 4.3x -0.1x -0.4x -0.6x 0.91x 0.75x -0.16x NBL $30.30 $ % 6.3x 5.4x 3.9x 8.1x 6.7x 4.5x +1.8x +1.4x +0.6x 0.68x 0.78x +0.10x OXY $64.96 $ % 6.8x 6.9x 7.3x 7.2x 7.0x 7.6x +0.4x +0.1x +0.3x 1.16x 0.96x -0.21x DVN $31.79 $ % 5.8x 5.0x 4.5x 7.1x 5.9x 5.2x +1.3x +1.0x +0.7x 0.65x 0.85x +0.20x EOG $ $ % 8.3x 7.4x 6.7x 9.3x 8.0x 7.0x +1.0x +0.6x +0.4x 1.13x 1.15x +0.03x Large-Cap Average 20.1% 6.1x 5.7x 5.4x 6.7x 6.1x 5.6x +0.6x +0.4x +0.2x 0.87x 0.94x +0.06x Source: Company data, Credit Suisse estimates, the BLOOMBERG PROFESSIONAL service; Embedded Midland/Waha strip prices are shown in Figure 8 and 11. Note: PDCE, QEP, SM, WPX, and OAS also have Permian exposure, but are included in Ex. Permian-Focused Oil Avg for better reflection of Permian-levered E&P underperformance Oil & Gas E&P 2

3 We believe last Friday s Permian sell-off was catalyzed by comments from ConocoPhillips CEO about potentially slowing down Permian activity due to the widening differential. However, the vast majority of E&Ps have not (publically) expressed concerns, or announced changes, around projected activity levels in 2H18. This is perhaps due to the fact that 1) companies are not currently seeing meaningful tightness in their physical ability to move barrels out of basin, supporting their confidence in near-term takeaway capabilities; 2) as E&P budgets were largely set using a $50-55/Bbl deck at the start of the year, realized oil prices are still largely better than base case projections despite wider differentials due to higher WTI prices; and 3) pure play Permian E&Ps don't have the alternate option of reallocating capital, unlike diversified large-caps, such as COP. That said, the landscape may change in 2H18 if the Permian takeaway bottlenecks do worsen as one would expect when pipeline capacity utilization rises to ~96% at the end of This may either cause severe physical constraints that would limit production, or substantially wider differentials which could prompt E&Ps to reassess their development plans, in particularly for An economic case could also be made to defer completions as we'd note that the pre-tax NPV per well would improve ~10% if delayed 9 months into a ($3)/Bbl differential vs. a ($20)/Bbl differential. As such, we would not be surprised if companies back-end weigh growth to 2H19 in a constrained environment, which could mean downside to consensus expectations. As operators uniformly claim flow assurance, it s difficult to assess whose barrels are more likely to face physical constraint and which companies are more willing to slowdown for economic reasons. Until proven otherwise, investors seem skeptical of existing 2H growth estimates for most Permian E&Ps except for those with true firm transport agreements (OXY, PXD, WPX best positioned, followed by APC, DVN, EOG that have FT on a portion of Permian volumes). Companies with Gulf Coast linked firm sales agreements (PE, PDCE, and QEP) are also relatively better positioned. To assess downside from operational risks, we ran a more draconian scenario for the Permian E&Ps assuming companies begin deferring completions starting in 4Q18 and keep production essentially flat from 3Q18 through 4Q19 (modest growth for companies with Gulf Coast linked contracts) but have completions ramp back to current assumptions in Under the material slowdown case, we see 2019 EV/EBITDX expanding by another 1.1x and 2020 EV/EBITDX widen by 0.5x at strip prices and with a 4.8% impact on NAV. Looking at it another way, to keep 2020 multiples unchanged from current levels, the slowdown scenario would infer an average downside of ~14.0% from current levels, though we d argue part of this is somewhat priced in with Permian already trading at just 0.4x above non-permian E&Ps on 2020 metrics. Figure 2: Valuation under ex-growth scenario Based on WTI and basis at current strip prices Current Strip Case EV/EBITDX (Strip Price Deck) Material Slowdown Case Absolute Change Absolute Ticker 2018E 2019E 2020E 2018E 2019E 2020E 2018E 2019E 2020E Strip down Change Downside To Maintain 2020 Multiple In Slowdown Case SM 6.7x 5.0x 4.0x 6.8x 5.9x 4.6x +0.1x +0.9x +0.7x 0.67x 0.76x +0.09x -30.1% -11.9% LPI 5.1x 4.7x 4.1x 5.1x 5.6x 4.7x 0.0x +0.9x +0.6x 0.71x 0.74x +0.03x -20.7% -4.5% CPE 8.0x 6.4x 4.8x 8.4x 8.6x 5.6x +0.4x +2.1x +0.8x 0.67x 0.72x +0.05x -19.8% -6.9% CDEV 7.9x 7.0x 5.0x 8.1x 9.0x 5.8x +0.2x +2.0x +0.8x 0.70x 0.73x +0.03x -16.1% -4.2% CXO 10.5x 7.8x 5.4x 10.5x 9.6x 6.3x 0.0x +1.8x +0.9x 0.84x 0.90x +0.06x -16.0% -6.3% JAG 7.5x 6.2x 4.6x 7.5x 7.8x 5.2x 0.0x +1.6x +0.6x 0.67x 0.72x +0.05x -15.6% -7.5% EGN 7.8x 6.2x 4.5x 8.0x 7.7x 5.1x +0.1x +1.5x +0.6x 0.83x 0.85x +0.02x -15.0% -1.9% FANG 10.0x 7.2x 5.1x 10.2x 9.0x 5.8x +0.2x +1.8x +0.7x 0.80x 0.82x +0.03x -14.0% -3.1% QEP 6.4x 6.2x 5.4x 6.5x 6.6x 5.8x 0.0x +0.4x +0.4x 0.89x 0.96x +0.07x -13.9% -7.2% XEC 6.8x 5.8x 4.7x 6.9x 6.8x 5.3x +0.1x +1.0x +0.6x 0.73x 0.77x +0.04x -13.2% -4.7% PE 8.3x 6.9x 5.7x 8.4x 7.7x 6.0x 0.0x +0.8x +0.3x 0.68x 0.70x +0.03x -7.2% -3.8% PDCE 5.6x 4.6x 4.0x 5.6x 4.8x 4.0x 0.0x +0.2x 0.0x 0.95x 0.96x +0.01x -0.6% -1.0% WPX 9.6x 6.5x 5.5x 9.6x 6.5x 5.5x 0.0x 0.0x 0.0x 0.78x 0.78x +0.00x 0.0% -0.1% Avg. 7.7x 6.2x 4.8x 7.8x 7.4x 5.4x +0.1x +1.1x +0.5x 0.76x 0.80x +0.04x -14.0% -4.8% Current P/NAV Slow- % Change In NAV Source: Company data, Credit Suisse estimates, the BLOOMBERG PROFESSIONAL service Oil & Gas E&P 3

4 Permian-focused E&Ps with back-end weighted production growth profiles carry more operational risk. Given Midland basis differentials are expected to be widest in 2H18, those we forecast to have 2H18 weighted completion and production growth profiles are most at risk should we 1) run out of takeaway capacity, or 2) see basis widen even further from here which could prompt operators to revisit their 2018 programs and potentially delay completions. Amongst our SMID-Cap E&Ps we see XEC, EGN and CPE as most exposed as they have a combination of 2H18 weighted completion schedules & growth profiles, and have a majority of volumes exposed to Midland basis (see Figure 12 for an updated summary of pricing exposure by operator). Large-Cap E&Ps who screen poorly under the below analysis include APC and NBL. Figure 3: CSe total completion cadence by quarter 1Q18 2Q18 3Q18 4Q18 XEC 11% 20% 35% 34% EGN 22% 14% 27% 37% APC 18% 20% 31% 32% DVN 22% 15% 27% 35% CXO 19% 24% 30% 27% NBL 17% 26% 28% 29% CPE 18% 25% 29% 27% FANG 20% 24% 27% 30% CDEV 21% 25% 26% 28% APA 32% 14% 26% 28% LPI 30% 16% 28% 25% PDCE 23% 23% 27% 27% OXY 19% 30% 29% 22% PXD 24% 25% 26% 25% JAG 29% 21% 23% 27% WPX 24% 26% 25% 25% PE 30% 21% 24% 25% SM 18% 36% 22% 24% QEP 26% 35% 23% 16% 0% 25% 50% 75% 100% % of FY2018 Completion Activity Source: Company data, Credit Suisse estimates Figure 4: CSe Permian oil growth split - 1H vs 2H18 EGN* XEC CPE LPI SM APC FANG NBL CDEV PDCE OXY PE PXD WPX CXO DVN QEP JAG APA** 2% 28% 31% 34% 35% 1H18 Growth 37% 47% 49% 49% 53% 55% 55% 57% 58% 67% 73% 80% 100% 98% 100% 2H18 Growth 72% 69% 66% 65% 63% 53% 51% 51% 47% 45% 45% 43% 42% 33% 27% 20% 0% 25% 50% 75% 100% % of FY2018 Permian Oil Bbld Added Source: Company data, Credit Suisse estimates Notes: *We forecast EGN s production to decline in 1H18 and show 100% of growth in 2H18 as a manually adjusted result. **We forecast the opposite for APA, their forecasted Permian oil growth is negative in 2H18 so we show 100% of 2018 growth in 1H18. Companies that are outspending at strip differential, particularly those with above average leverage metrics, are also more likely to cut spending. Below we quantify the impact of running strip Midland and Waha basis through our models on both EBITDX and funding gaps across operators. Judging by capex plowback ratio, we note that JAG, LPI, CDEV, CPE, and SM have the highest outspend ratios as % of total cash flow in 2019 based on current activity estimates. The funding deficits should be viewed along with leverage metrics and among the higher levered E&Ps, we believe LPI and QEP (Permian standalone) are most likely to decide against a ramp up or scale back in While SM Oil & Gas E&P 4

5 also has above average leverage, it has sufficient cash on hand to bridge a larger cash flow deficit if it s current growth plans are unaffected by basin takeaway constraints. However, its goal of reaching cash flow neutrality by 2019 would be pushed out to 2020 assuming current strip differentials. Figure 5: Cash flow impact of strip Midland/Waha basis (without activity chg) Strip Case Estimates (+ Strip Basis) Disc. CF ($MM) Funding Gap ($MM) Plowback Leverage Ticker JAG $356 $466 ($281) ($260) 168% 147% 1.5x 1.6x LPI $495 $573 ($103) ($269) 121% 147% 1.8x 2.1x CDEV $644 $769 ($354) ($257) 157% 135% 1.0x 1.2x CPE $411 $569 ($99) ($47) 143% 124% 2.7x 2.0x SM $621 $923 ($639) ($200) 205% 123% 3.5x 2.7x EGN $907 $1,203 ($261) ($276) 129% 123% 1.3x 1.3x QEP $758 $833 ($375) ($84) 156% 110% 3.5x 3.3x PE $1,174 $1,493 ($350) ($147) 130% 110% 1.7x 1.5x XEC $1,377 $1,654 ($380) ($90) 128% 105% 1.1x 1.0x NBL $2,480 $3,039 ($838) ($258) 128% 104% 2.3x 1.9x CXO $2,356 $3,607 $308 $39 88% 99% 1.7x 1.1x PDCE $870 $1,094 ($7) $93 101% 92% 1.5x 1.1x FANG $1,271 $1,813 ($125) $ % 88% 1.6x 1.0x WPX $865 $1,429 ($334) $ % 87% 2.7x 1.5x EOG $7,415 $8,473 $1,397 $894 76% 83% 0.5x 0.3x PXD $3,319 $4,209 $231 $679 91% 83% 0.4x 0.2x DVN $3,558 $4,254 $272 $897 88% 74% 2.2x 1.7x APA $3,238 $3,718 ($245) $633 97% 74% 1.8x 1.7x APC $6,441 $7,768 $687 $2,186 79% 66% 1.7x 1.2x OXY $7,693 $7,731 $1,739 $1,809 51% 49% 0.8x 0.7x Source: Company data, Credit Suisse estimates, the BLOOMBERG PROFESSIONAL service We are downgrading SM from Outperform to Neutral and lowering price target from $26/share to $25/share. SM has outperformed the Permian E&Ps by over 30% since the end of March despite its meaningful Permian exposure. Given the stock price move, SM is now trading at 6.7x and 5.0x on EV/EBITDX, a 1x discount to the broader oily resource E&P universe, which we view as appropriate given Permian takeaway risks and its above average leverage. Our new price target of $25/share is based on a blended target multiples of 5.0x 2019 EV/EBITDX and 0.7x NAV, reflecting the cash flow changes from widening of Mid-Cush oil differential. We believe SM s risk/reward is more balanced going forward for two reasons: First, we believe SM s discount valuation is appropriate given it has greater than average downside risk in a constrained Permian takeaway environment. The company s 2-year transition and de-leveraging plan is highly reliant on meaningful oil production and cash flow growth from the Permian. Our prior thesis was based on expectations of strong execution in the Permian enabling the company to reach cash flow neutrality by mid-2019 and de-lever the company from 4.0x net debt/ebitdx at YE17 to its goal of 2.5x by YE19. While Permian execution has exceeded expectations to date, future growth could be at risk if the basin, as a whole, is seeing physical takeaway constraints due to lack of available pipeline capacity. Although SM has some basis hedge protection (71% in 2018 and 44% in 2019) and has promised flow assurance via firm sales agreements with 3rd party marketers, it s overall positioning is not much differentiated vs. other Permianlevered E&Ps. Meanwhile, the financial implications from any downside to Permian oil production growth are greater for SM given its already above average leverage. Oil & Gas E&P 5

6 Second, We continue to see meaningful downside to consensus 2H18 and 2019 oil production estimates even assuming Permian executing above company expectations and growing without the impact of takeaway constraints. We remain concerned about still too high consensus oil production estimates due to 1) multiple oily asset sales (Powder River and Divide County) that will be completely removed from 2H18 production; and 2) development cadence guidance provided with 4Q17 results that reflected a slowdown in Permian activity as the company plans to exit 2018 with 7 rigs in the Permian, down from 9 rigs in 1Q18, and will have flattish completions YoY. Reflecting the asset sales and development cadence, our oil production forecasts are ~5% below consensus in 2H18 and ~7% in 2019 (61.1 MBbld vs. consensus of 65.7 MBbld). And those estimates assume robust Permian oil growth to 50 MBbld in 4Q18 from ~37 MBbld in 1H18 reflecting timing of completions and ~58 MBbld in Notably, implied oil production from SM s own % hedged forecasts for 2019 are closer to our forecasts, as such, we see consensus downward revisions as a headwind in 2H18. What can remove Permian operational overhang? Certainly, the best case scenario is for Permian operators to indeed bring production to market via current marketing agreements and maintain development plans thanks to higher WTI prices, disproving existing investor concerns. Otherwise, we see two paths for the market to lift the uncertainty overhang around Permian stocks. Path #1: The harder way is any signal for potential deferral or slow down of activity level, leading to negative estimate revisions. As we have shown in the downside scenario implications above, lower activity would be most impactful to growth estimates and valuation. We believe company comments, whether official or unofficial, could surface later in the year if differential remain at or wider than current levels, physical constraints worsen, or as company evaluate 2019 plans, they could point to a more back-end weighted than consensus estimates today. Already, ConocoPhillips CEO indicated at a conference last week that the company is evaluating whether to reallocate capital away from the Permian as a result of wider differential. Path #2: The easier solution (albeit with a higher level of market skepticism and only available to a limited number of companies) may be more firm sales marketing agreements, such as the one PDCE signed, that provides flow assurance and removes the uncertainty of a worst-case differential scenario that could put late operations at risk. PDCE stood out as it was the only E&P that announced a new Permian marketing agreement with 1Q results. Based on our analysis of that marketing contract, the terms are overwhelmingly favorable to PDCE due to Brent-linked nature of the contract (more details below). It's difficult to see contract terms as favorable as PDCE's is still available today (or rationalize how that was ever an option from midstream perspective). However, we'd view it as a positive if E&Ps can sign multi-year contracts even on a NPV-neutral basis today (i.e. In-the-money contract prices in the near term offset by higher costs in the outer years). Notably, such options are exactly what FANG is actively evaluating, as the company has publicly stated that they are exploring ways to leverage their LT commitment on the Grey Oak pipeline to get better than market pricing in the very near term. We believe the takeaway concerns and perhaps perception of an exceptionally tight market may be substantially alleviated if more E&Ps follow suit with new marketing agreements. A closer look at PDCE s marketing agreement. With 1Q earnings, PDCE surprised the market with a new firm sales agreement signed with a 3rd party marketer that covers ~85% of Delaware oil production. The agreement spans 5.5 years (starting 2H18) with volumes under contract growing from 11.4 MBbld initially to ultimately 26 MBbld, providing PDCE with flow assurance on firm takeaway and favorable Brent-weighted pricing as volumes will be sold at Corpus Christi. As a result, Oil & Gas E&P 6

7 Figure 6: PDCE takeaway contract analysis PDCE expects to realize 88-92% of WTI pricing for all of its Delaware basin oil volumes. Based on information available in the 10Q filing and our conversations with the company, we infer the contract cost of only a modest ~$ /Bbl on average over life of the agreement, albeit higher in the first 2 years, and lower in the outer years. In exchange, the barrels will be sold at Brent-linked prices, and given material widening of the Brent-WTI spread to ~$11/Bbl currently, the contract is very attractively "in the money" for the duration of the term. Implications for other E&Ps. From E&Ps perspective, such contract provides valuable protection from a draconian downside scenario at a time when investors are overwhelmingly focused on Midland basis differentials. Such protection is particularly important for a company in the early growth stage of the play... such as PDCE and even with substantially less favorable terms (i.e. neutral NPV), the trade-off is justified. Moreover, while the contract covers the majority of volumes near-term the impact is diluted over time as production is forecasted to grow well in excess of the committed volumes. Date 2H CS Est. Committed Volumes (Bbld) 13,700 22,308 23,265 21,066 20,219 23,419 CS Est. Contract Price ($/Bbl) ($5.00) ($5.00) ($3.87) ($3.87) ($3.87) ($3.87) Total Cost CS Est. Contract Cost ($MM) ($12.6) ($40.7) ($32.8) ($29.7) ($28.5) ($33.1) ($177.5) Contract Valuation As Of 5/1/2018 WTI Futures Strip ($/Bbl) $66.02 $61.33 $56.43 $53.26 $51.41 $50.46 Midland Basis ($/Bbl) ($10.68) ($6.29) ($0.84) ($0.15) ($0.15) ($0.15) Ex. Contract Est. Realization ($/Bbl) $55.34 $55.05 $55.59 $53.11 $51.26 $50.31 Brent Futures Strip ($/Bbl) $71.96 $67.95 $63.44 $60.42 $58.75 $57.90 CS Est. Contract Price ($/Bbl) ($5.00) ($5.00) ($3.87) ($3.87) ($3.87) ($3.87) Incl. Contract Est. Realization ($/Bbl) $66.96 $62.95 $59.57 $56.55 $54.88 $54.04 Est. Contract Impact ($/Bbl) +$ $7.90 +$3.98 +$3.44 +$3.63 +$3.72 NPV (10%) Implied Contract Valuation - 5/1 ($MM) $29.3 $64.3 $33.8 $26.5 $26.8 $31.8 $157.9 Source: Company data, Credit Suisse estimates, the BLOOMBERG PROFESSIONAL service Oil & Gas E&P 7

8 Update on Permian Takeaway Since our April 13 th Permian Takeaway note, there has been several changes to the Permian oil S/D balance with higher production forecasts and expanded takeaway capacity starting mid However, the next pipeline relief may be delayed in the interim due to new capacity expansion, resulting in a tighter balance from now through 3Q19. On the supply side: YTD Permian completions were above our expectations, which grew ~17% QoQ according to the EIA s Drilling Productivity Report even though our universe s Permian activity fell 2% QoQ. The Permian E&Ps in our coverage also beat oil production estimates by ~3% in aggregate in 1Q. Assuming muted activity growth from current levels, we now forecast Permian production to grow from ~3.2 MMBbld currently to ~3.44 MBbld in 4Q18 and ~4.13 MMBbld in 4Q19, up ~40 MBbld from prior forecasts. On the takeaway front: There were 3 major developments: 1) Cactus II expanded from 585 to 670 MBbld; 2) Grey Oak expanded from 385 MBbld to 700 MBbld (expandable to 1 MMBbld); and 3) a new 600 MBbld pipeline announced by ETP starting 2020 (expandable to 1 MMBbld). These changes combined increased our YE2020 capacity from 6.1 MMBbld to ~6.6 MMBbld, but put more questions on timing of 2H19 additions as Cactus II may be delayed from 3Q19 to 4Q19 due to the expansion, while there s an increased level of skepticism around an on-time start-up of the EPIC pipeline currently slated for 4Q19. Based on these changes, we estimate takeaway capacity utilization currently sits at 85+%, which grows to 96% by YE18 and peak at 100% in 2Q19. Spot Midland-Cushing spread has been volatile due to planned/unplanned downtime at the Borger and Big Springs refineries, signaling a tight market which will likely tighten much more in 2H18. As such, we have also revised our base case scenario assuming differentials of $10-12/Bbl in 4Q18 & 1Q19, and stay wider for longer in 2H19 vs. our prior estimates. Our admittedly still conservative forecasts reflect return of the Permian basin refineries and ~160 MBbld of incremental pipeline capacity addition in 1Q19. Figure 7: CSe Permian Crude Production vs. Takeaway Capacity ( ) 7.0 CS Permian Oil Production Forecast (Incl. Bobcat Volumes) MMBbld Implied Capacity Ultization Expected Expansion Capacity 2.0 Current Takeaway Capacity Local Refinery Capacity (Including 80 MBbld of Rail) See page 12 for a detailed table of expansion projects and our Permian production forecast by quarter. Source: Company data, Credit Suisse estimates Oil & Gas E&P 8

9 Figure 8: Move in Mid- Cushing Basis Strip Prices ($0.3) $0 ($2) ($0.4) ($4) ($6) ($8) ($10) ($12) ($14) ($16) ($18) ($6.6) ($9.1) ($10.4) ($7.9) ($9.1) ($12.4) ($12.8) ($14.8) ($11.6) ($14.3) ($16.6) ($14.0) Source: the BLOOMBERG PROFESSIONAL service ($2.8) ($3.6) Early April Strip May 23rd Strip June 1st Strip ~($0.50) Figure 9: Update to CS Mid-Cush Basis assumption $0 ($2)($0) ($4) ($6) ($8) ($10) ($12) ($14) ($16) ($18) ($5) ($9) ($6) ($10) Source: Credit Suisse estimates ($8) ($8) ($12) ($10) ($6) ($8) ($2) ($6) ($1) ($0.50) ($2) Old Base Case New Base Case ($1) Permian gas takeaway will also be a constraint through 2H19, though gas flow assurance is much more important than pricing differentials for operators given limited revenue impact of natural gas. With Permian natural gas production reaching ~7.2 Bcfd currently, the basin s production is approaching takeaway capacity of 8.5 Bcfd. Reflecting these concerns, Waha basis futures has widened ~$0.40/MMBtu YTD to ~$1.20/MMBtu, albeit has stabilized in recent weeks. While Permian Basin pipeline takeaway capacity is at 73%, Platt s estimates effective utilization is 86% after adjusting for lower downstream demand resulting from increased gas production in the Anadarko Basin and San Juan Basin filling markets traditionally supplied by the Permian. Given Permian gas production has grown nearly 1 Bcfd since October and effective spare capacity is just 14% (or 1.2 Bcfd) according to Platt s, associated gas production could be significantly constrained starting 2H18. Flow assurance rather than pricing is much more important for Permian given its essentially a byproduct of oil growth and gas flaring, while permissible for up to 6 months with permits, is far from desirable. Currently, two 2.0 Bcfd each projects are slated to be online in late 2019 that should remove the bottleneck - Kinder Morgan s Gulf Coast Express Pipeline and NAmerico Partners Pecos Trail pipeline. However, the latter carries higher timing risk as it s backed by an infrastructure PE fund, and still unclear whether adequate shipper commitments has been secured. That being said, it s much easier and faster to build or expand the intrastate pipeline network, which is not regulated by FERC, which could provide near term Band-Aid relief. Case in point is an expansion just recently announced by Enterprise/Energy Transfer in early May that can add 150 MMcfd on the North Texas Pipeline as soon as late 2019, which moves Waha gas east and then eventually down to the Gulf Coast. Figure 10: 2018 Unhedged revenue split by product 100% 90% 80% 70% 60% 50% Oil NGL Gas 5% 2% 9% 9% 2% 4% 4% 3% 8% 8% 10% 11% 12% 7% 8% 6% 13% 5% 11% 13% 16% 94% 91% 91% 90% 88% 86% 86% 83% 82% 78% 78% 70% 17% Figure 11: Waha gas prices ($/MMBtu) ($0.50) ($0.75) ($1.00) ($1.25) ($1.50) ($1.75) ($2.00) Base Strip Source: Company data, Credit Suisse estimates Source: Credit Suisse estimates, the BLOOMBERG PROFESSIONAL service Oil & Gas E&P 9

10 E&P Takeaway Positioning With a few exceptions, our company-level views on takeaway exposure are unchanged and the 1Q update largely reinforced our view that there is not much differentiation among E&Ps that sell production at the wellhead, and receive Midland-based pricing. Large-Caps are in general much better positioned than SMID-Cap E&Ps. Companies best positioned are those that control their destiny from wellhead to end-markets by using company-owned gathering system, and have FT on long-haul pipelines to move crude to more favorably priced destinations i.e. East Houston and Corpus Christi. Notable 1Q updates, PDCE had the most upside surprise (for the medium term) as it announced a 5.5- year Brent-based firm sales agreement with 1Q earnings that will benefit medium term pricing and flow assurance, while the long-term implications and less clear and mostly a function of the Brent-WTI spread in the outer years. XEC delivered a positive update on gas firm sales with their 1Q update, as it has agreements in place to move over 98% of its forecasted gas production through October 2019, offering gas flow assurance. It also has similar agreements in place for oil sales. Meanwhile, FANG signed up for 50 MBbld on the Gray Oak pipeline, which starts in late 2019, but didn t address takeaway and pricing concerns, which has been somewhat of a disappointment. However, we believe a solution for the medium term is in the works and could be announced in the near future. LPI negatively surprised the market by announcing a contract dispute with Shell that reduced its amount of production exposed to advantaged Gulf Coast pricing from ~90% to ~35%. Within the Permian-levered E&P universe, we continue to view PXD and WPX best positioned on takeaway as both have true firm transport agreements to the Gulf Coast. PDCE, and PE are also relatively better positioned due to Gulf Coast linked firm sales agreements that covers a substantial portion of its oil volumes. Below we provide an updated summary which combines FT/firm sales agreements and current Mid- Cush hedges to highlight each operator s relative degree of exposure to Midland pricing. Figure 12: Midland pricing exposure by operator % Permian Oil Exposed to Gulf Coast/Cushing Pricing % Permian Oil Covered by Basis Swaps % Permian Production Exposed to Midland Pricing Ticker 2H H H FANG 0% 0% 17% 0% 83% 100% CPE 0% 0% 48% 8% 52% 92% CDEV 0% 0% 22% 9% 78% 91% XEC 0% 0% 30% 15% 70% 85% JAG 0% 0% 51% 21% 49% 79% LPI 34% 28% 34% 0% 32% 72% EGN 0% 0% 62% 29% 38% 71% SM 0% 0% 71% 44% 29% 56% PE 57% 48% 15% 0% 28% 52% CXO 0% 0% 71% 50% 29% 50% QEP 30% 35% 68% 28% 2% 37% PXD 89% 78% 0% 0% 11% 22% PDCE 85% 85% 34% 0% 0% 15% WPX 84% 142% 35% 40% 0% 0% Average 27% 30% 40% 17% 36% 59% Source: Company data, Credit Suisse estimates Oil & Gas E&P 10

11 Estimate Changes Summary Our revised Midland basis forecast moves our 2018/2019 CFPS estimates for Permian focused E&Ps lower by ~2.7% and ~3.5%, respectively, as we now forecast the Midland basis differential to peak at $12/Bbl in 4Q18. We are also lowering price targets for Permian focused E&Ps by ~4%. Figure 13: Estimate and TP change summary Old CFPS Estimates New CFPS Estimates Ticker Old TP New TP APA $8.60 $9.80 $8.40 $9.65 $40 $40 APC $12.85 $15.95 $12.75 $15.90 $77 $77 CDEV $2.50 $3.20 $2.40 $3.05 $23 $22 CPE $2.00 $2.85 $1.95 $2.70 $15 $14 CXO $14.20 $20.00 $13.85 $19.35 $168 $168 DVN $6.85 $8.65 $6.85 $8.70 $45 $45 EGN $9.60 $13.60 $9.60 $12.00 $72 $70 EOG $12.85 $15.25 $12.80 $15.20 $120 $120 FANG $14.40 $21.10 $13.15 $18.65 $145 $140 JAG $1.75 $2.45 $2.05 $2.95 $15 $14 LPI $2.20 $2.85 $2.15 $2.75 $10 $9 NBL $5.30 $6.80 $5.15 $6.65 $44 $44 OXY $9.55 $9.95 $9.80 $10.10 $80 $80 PDCE $13.15 $17.05 $13.15 $17.05 $61 $61 PE $3.80 $5.10 $3.75 $5.05 $37 $36 PXD $19.50 $25.65 $19.45 $24.95 $245 $245 QEP $3.20 $3.70 $3.30 $4.35 $11 $11 RSPP $5.75 $7.85 $5.60 $7.55 $54 $54 SM $5.70 $9.05 $5.65 $8.75 $26 $25 WPX $2.25 $3.55 $2.16 $3.57 $19 $19 XEC $14.85 $18.45 $15.90 $20.10 $120 $114 Source: Company data, Credit Suisse estimates Oil & Gas E&P 11

12 Oil & Gas E&P 12 Figure 14: Permian supply and demand table Units: MBbld Operator Origination Destination Q18E 2Q18E 3Q18E 4Q18E Q19E 2Q19E 3Q19E 4Q19E Pipelines Amdel Pipeline ETP Midland, TX Nederland, TX Basin Pipeline + Expansion PAA Colorado City, TX Cushing, OK BridgeTex Pipeline + Expansion MMP Colorado City, TX Houston, TX Cactus Pipeline PAA McCamey, TX Gardendale, TX Centurion Pipeline OXY Permian Cushing, OK Line 80 PSXP Hobbs, NM Borger, TX Longhorn Reversal + Expansion MMP El Paso, TX Houston, TX Midland to Sealy Pipeline EPD Midland, TX Sealy, TX Permian Express I ETP Midland, TX Nederland, TX Permian Express II ETP Midland, TX Nederland, TX Permian Express III Phase 1 ETP Midland, TX Nederland, TX Permian Longview & Louisiana Extension ETP Midland, TX Longview, TX WA Line PSXP Goldsmith, TX Borger, TX West Texas Gulf ETP Colorado City, TX Longview, TX West Texas Gulf Exp - Houston Access ETP Colorado City, TX Houston, TX West Texas Gulf Exp - Longview Access ETP Colorado City, TX Longview, TX West Texas Gulf Exp - Nederland Access ETP Colorado City, TX Nederland, TX Wink Pipeline KMI Scurry, Texas El Paso, TX Total Pipelines 2,842 2,992 2,992 2,992 2,992 2,992 3,032 3,032 3,032 3,032 3,032 3,032 3,032 3,032 Potential Expansions Midland to Sealy Pipeline Expansion EPD Midland, TX Sealy, TX Sunrise Extension + Loop PAA Midland / Colorado City, TX Wichita Falls, TX Permian Express III Phase 2 ETP Midland, TX Corsicana, TX Cactus II PAA Permian Basin Corpus Christi, TX TexStar Midstream Logistics EPIC Pipeline Castleton / Orla, Pecos, Crane, & Ironwood Midland, TX Corpus Christi, TX NGL Pipeline Conversion EPD Permian Basin Mont Belvieu, TX Grey Oak Pipeline PSX / ENB West Texas Corpus Christi, TX Permian to Corpus Christi MMP Permian Basin Corpus Christi, TX Permian to Nederland ETP Permian Basin Nederland, TX Total Potential Expansion Capacity ,190 1,780 1,780 3,630 3,630 3,630 Refineries % of Capacity Big Spring Refinery DK Big Spring, TX 100% Borger (Net from Permian) PSX Borger, TX 100% El Paso (via KMI Wink Pipeline) ANDV El Paso, TX 100% Gallup ANDV Gallup, NM 100% Navajo Refinery HFC Navajo, NM 100% Total Refineries Total Demand (Incl. 80 MBbld of Rail) 3,290 3,520 3,720 3,720 3,720 3,720 3,880 3,880 4,750 5,340 5,340 7,190 7,190 7,190 Production Permian Crude Production 2,483 2,955 3,156 3,311 3,439 3,215 3,590 3,757 3,919 4,130 3,849 4,643 5,317 5,887 YoY Change Total Production 2,483 2,955 3,156 3,311 3,439 3,215 3,590 3,757 3,919 4,130 3,849 4,643 5,317 5,887 Inbound Pipelines Bobcat Pipeline ANDV Mason Station, TX Wink Station, TX Total Inbound Pipelines Total Supply 2,608 3,080 3,281 3,436 3,564 3,340 3,715 3,882 4,044 4,255 3,974 4,768 5,442 6,012 Implied Capacity Utilization 79% 87% 88% 92% 96% 90% 96% 100% 85% 80% 74% 66% 76% 84% Source: Company data, Credit Suisse estimates 4 June 2018

13 Americas/United States Oil & Gas Exploration & Production Rating OUTPERFORM Price (31-May-18, US$) Target price (US$) (from 23.00) week price range (US$) Market cap(us$ m) 4,859 Enterprise value (US$ m) 5,497 Target price is for 12 months. Research Analysts Betty Jiang, CFA Chris Baker, CFA Centennial Resource Development, Inc. (CDEV) Updating Estimates Updating Estimates. We are updating our estimates based on our revised Midland basis forecast. The net effect of our changes moves our 2018/2019 CFPS to $2.40/$3.05 from $2.50/$3.20 prior. Valuation. We re lowering our TP to $22 from $23, based on 8.5x normalized 2019 EBITDA and ~0.8x NAV. Risk to our thesis include materially lower oil prices CDEV.OQ NASDAQ NM S COM POSITE INDEX On 31-May-2018 the NASDAQ NMS COMPOSITE INDEX closed at Daily Jun01, May31, 2018, 06/01/17 = US$15.78 Quarterly Q1 Q2 Q3 Q4 CFPS 2017A E E Financial and valuation metrics Year 12/17A 12/18E 12/19E 12/20E EBITDX (US$ m) ,165.7 CFPS (US$) Prev. CFPS (US$) DACF ,165.7 EPS (CS Adj.) (US$) ROACE (%) EV/EBITDX EV/DACF Net debt (US$ m) Dividend (current qtr., US$).0 Dividend yield (%) 0.0 Net debt (current, US$) Net debt/cap (%) 0.16 NAV/share (12/18E, US$ m) Net debt/ebitdx (x) 0.90 P/NAV (x) 0.6 Number of shares (m) Free float (%) 66.2 Oil & Gas E&P 13

14 Centennial Resource Development, Inc. (CDEV) Price (01 Jun 2018): US$16.92; Rating: OUTPERFORM; Target Price: (from 23.00) 22.00; Analyst: Betty Jiang Income Statement 12/17A 12/18E 12/19E 12/20E EBITDX (US$ m) ,166 DACF ,166 Net interest income (exp) Net non operating inc (exp) Share of associates/jvs' equity Exceptionals Profit before tax (US$ m) Taxes Profit after tax Extraordinary gain/(loss) (8) (5) 0 0 Non-controlling interest (minority) Preferred dividends Adjusted net income (US$ m) Cash Flow 12/17A 12/18E 12/19E 12/20E Change in working capital (21) (22) 0 0 Other cash and non-cash items Cash flow from operations ,135 Capex (566) (1,011) (1,027) (1,171) Acquisitions (440) (102) 0 0 Divestments Other investment/(outflows) Cashflow from investment (992) (979) (1,041) (1,185) Operating cash flow ,135.5 Balance Sheet 12/17A 12/18E 12/19E 12/20E Cash and cash equivalents Other current assets Total current assets Total fixed assets 3,386 3,993 4,571 5,178 Other assets Total assets 3,617 4,142 4,720 5,327 Total current liabilities Long-term debt Other Liabilities Total liabilities ,097 1,252 Shareholders' equity 3,004 3,292 3,622 4,075 Minority interest Total equity and liabilities 3,617 4,142 4,720 5,327 Per share 12/17A 12/18E 12/19E 12/20E Equiv. FPO (period Avg.) (mn) CFPS (US$) Prev. CFPS (US$) DPS (US$) Total Production 12/17A 12/18E 12/19E 12/20E Total Production (MBoed) Oil Production (MBbld) NGL Production (MBbld) Gas Production (MMcfd) Valuation 12/17A 12/18E 12/19E 12/20E Dividend yield (%) FCF yield (%) (6.2) (7.4) (3.3) (0.7) EV/EBITDX (x) Returns 12/17A 12/18E 12/19E 12/20E ROE (%) ROACE (avg.) (%) Gearing 12/17A 12/18E 12/19E 12/20E Net debt/cap (%) Interest coverage ratio (X) Company Background Centennial was originally incorporated as a special purpose acquisition company under the name Silver Run Acquisition Corp. for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, or reorganization. Blue/Grey Sky Scenario Our Blue Sky Scenario (US$) (from 30.00) Our Blue Sky Scenario assumes a flat $10/Bbl and $0.25/MMBtu premium to the normalized Credit Suisse price deck. Under this scenario, CDEV would be worth $28/sh. However, we note that at these oil and gas prices, CDEV would be generating additional free cash flow versus our base case. This extra cash would allow the company to accelerate drilling activity which could provide additional upside. Our Grey Sky Scenario (US$) (from 16.00) Our Grey Sky Scenario assumes a $10/Bbl and $0.25/MMBtu discount to the normalized Credit Suisse price deck. Under this scenario, CDEV would be worth $15/sh. However, we note that at these oil and gas prices, CDEV would be generating less free cash flow which could mean lower drilling activity than our base case. Under this scenario, value would be deferred and further downside could be warranted C D EV.O Q N A SD A Q N M S C O M PO SIT E IN D EX On 01-Jun-2018 the NASDAQ NMS COMPOSITE INDEX closed at Daily Jun02, Jun01, 2018, 06/02/17 = US$15.25 Oil & Gas E&P 14

15 Americas/United States Oil & Gas Exploration & Production Rating NEUTRAL Price (01-Jun-18, US$) Target price (US$) (from 72.00) week price range (US$) Market cap(us$ m) 6,301 Enterprise value (US$ m) 7,543 Target price is for 12 months. Research Analysts Betty Jiang, CFA Chris Baker, CFA Energen Corporation (EGN) Updating Estimates Updating Estimates. We are updating our estimates based on our revised Midland basis forecast. The net effect of our changes moves our 2018/2019 CFPS to $9.40/$13.10 from $9.60/$13.60 prior. Valuation. We re lowering our TP to $70 from $72, based on 7.0x normalized 2019 EBITDA and 0.7x NAV. Risk to our thesis include oil prices EGN.N On 01-Jun-2018 the S&P 500 INDEX closed at Daily Jun01, Jun01, 2018, 06/01/17 = US$58.0 Quarterly Q1 Q2 Q3 Q4 CFPS 2017A E E Financial and valuation metrics Year 12/17A 12/18E 12/19E 12/20E EBITDX (US$ m) , ,770.7 CFPS (US$) Prev. CFPS (US$) DACF 1, , ,797.6 EPS (CS Adj.) (US$) ROACE (%) EV/EBITDX EV/DACF Net debt (US$ m) 914 1,242 1,491 1,546 Dividend (current qtr., US$).0 Dividend yield (%) 0.0 Net debt (current, US$) 1,048.2 Net debt/cap (%) 0.26 NAV/share (12/18E, US$ m) Net debt/ebitdx (x) 1.31 P/NAV (x) 0.7 Number of shares (m) 97.4 Free float (%) 95.8 Oil & Gas E&P 15

16 Energen Corporation (EGN) Price (01 Jun 2018): US$64.11; Rating: NEUTRAL; Target Price: (from 72.00) 70.00; Analyst: Betty Jiang Income Statement 12/17A 12/18E 12/19E 12/20E EBITDX (US$ m) ,321 1,771 DACF 1, ,345 1,798 Net interest income (exp) Net non operating inc (exp) Share of associates/jvs' equity Exceptionals Profit before tax (US$ m) Taxes Profit after tax Extraordinary gain/(loss) Non-controlling interest (minority) Preferred dividends Adjusted net income (US$ m) Cash Flow 12/17A 12/18E 12/19E 12/20E Change in working capital (141) Other cash and non-cash items Cash flow from operations ,281 1,721 Capex (910) (1,168) (1,480) (1,726) Acquisitions (277) (53) (50) (50) Divestments Other investment/(outflows) Cashflow from investment (1,183) (1,220) (1,530) (1,776) Operating cash flow , ,721.2 Balance Sheet 12/17A 12/18E 12/19E 12/20E Cash and cash equivalents Other current assets Total current assets Total fixed assets 4,764 5,538 6,410 7,354 Other assets Total assets 5,034 5,811 6,683 7,627 Total current liabilities Long-term debt 783 1,070 1,319 1,374 Other Liabilities Total liabilities 1,595 2,028 2,412 2,663 Shareholders' equity 3,438 3,783 4,270 4,964 Minority interest Total equity and liabilities 5,034 5,811 6,683 7,627 Per share 12/17A 12/18E 12/19E 12/20E Equiv. FPO (period Avg.) (mn) CFPS (US$) Prev. CFPS (US$) DPS (US$) Total Production 12/17A 12/18E 12/19E 12/20E Total Production (MBoed) Oil Production (MBbld) NGL Production (MBbld) Gas Production (MMcfd) Valuation 12/17A 12/18E 12/19E 12/20E Dividend yield (%) FCF yield (%) (4.3) (4.8) (4.0) (0.9) EV/EBITDX (x) Returns 12/17A 12/18E 12/19E 12/20E ROE (%) ROACE (avg.) (%) Gearing 12/17A 12/18E 12/19E 12/20E Net debt/cap (%) Interest coverage ratio (X) Company Background Energen Corporation is an oil and natural gas exploration and production company engaged in the exploration, development and production of oil, natural gas liquids and natural gas. Blue/Grey Sky Scenario Our Blue Sky Scenario (US$) Our Blue Sky Scenario assumes a flat $10/Bbl and $0.25/MMBtu premium to our normalized $60/Bbl and $2.75/MMBtu price deck. Under this scenario, EGN would be worth $82/sh. However, we note that at these oil and gas prices, EGN would be generating additional free cash flow versus our base case. This extra cash would allow the company to accelerate drilling activity which could provide additional upside. Our Grey Sky Scenario (US$) (from 42.00) Our Grey Sky Scenario assumes a $10/Bbl and $0.25/MMBtu discount to our normalized $60/Bbl and $2.75/MMBtu price deck. Under this scenario, EGN would be worth $40/sh. However, we note that at these oil and gas prices, EGN would be generating less free cash flow which could mean lower drilling activity than our base case. Under this scenario, value would be deferred and further downside could be warranted EGN.N On 01-Jun-2018 the S&P 500 INDEX closed at Daily Jun02, Jun01, 2018, 06/02/17 = US$56.67 Oil & Gas E&P 16