FEBRUARY EARNINGS PRESENTATION

Transcription

1 FEBRUARY EARNINGS PRESENTATION

2 Certain Disclosures Forward Looking Statements This presentation contains forward-looking statements. These forward-looking statements can be identified by use of forward-looking terminology including may, could, should, assume, estimate, project, believe, plan, expect, anticipate, intend, forecast, continue or other similar words. These statements discuss future operating or financial performance or events. Descriptions of Legacy s objectives, goals, targets, plans, strategies, budgets and projected financial and operating performance are also forward-looking statements. These statements represent our present expectation or beliefs concerning future events and are not guarantees. Such statements speak only as of the date they are made, and Legacy does not undertake any obligation to update any forward-looking statement. We caution that forward-looking statements involve risks and uncertainties and are qualified by important factors that could cause actual events or results to differ materially from those expressed or implied in any such forward-looking statements. Investors are also urged to consider closely the disclosure relating to Risk Factors and Forward-Looking Statements in Legacy s Annual Report on Form 10-K for the year ended December 31, 2017 to be filed on or about February 23, 2018 (the Annual Report ), and subsequent filings with the Securities Exchange Commission (the SEC ). The Annual Report is available from Legacy s website at You can also obtain the Annual Report from the SEC by visiting EDGAR. Reserve Estimates The SEC permits oil and natural gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC s definitions for such terms. Legacy discloses proved reserves but does not disclose probable or possible reserves. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Legacy may use terms in this presentation that the SEC s guidelines strictly prohibit in SEC filings, such as estimated ultimate recovery or EUR, resource potential, development potential, potential bench and similar terms to estimate oil and natural gas that may ultimately be recovered. Legacy defines EUR as estimates of the sum of reserves remaining as of a given date and cumulative production as of that date from a currently producing or hypothetical future well, as applicable. These broader classifications do not constitute reserves as defined by the SEC. Estimates of such broader classification of volumes are by their nature more speculative than estimates of proved, probable and possible reserves as used in SEC filings and, accordingly, are subject to substantially greater uncertainty of being actually realized. You should not assume that such terms are comparable to proved, probable and possible reserves or represent estimates of future production from properties or are indicative of expected future resource recovery. Actual locations drilled and quantities that may be ultimately recovered will likely differ substantially from these estimates. Factors affecting ultimate recovery include the scope of Legacy s actual drilling program, availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, actual encountered geological conditions, lease expirations, transportation constraints, regulatory approvals, field spacing rules, actual drilling results and recoveries of oil and natural gas in place, and other factors. These estimates may change significantly as the development of properties provides additional data. Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Investors are also urged to consider closely the disclosure relating to Risk Factors in the Annual Report and subsequent filings with the SEC, which are available from Legacy s website at or on the SEC s website at for a discussion of the risks and uncertainties involved in the process of estimating reserves. Identified Drilling Locations Our estimates of gross identified potential drilling locations (as used herein, locations, identified locations, identified horizontal locations or identified drilling locations ) are prepared internally by our engineers, geologists and management and are based upon a number of assumptions inherent in the estimates process. Management, with the assistance of our engineers and other professionals, as necessary, conducts a topographical analysis of our unproved prospective acreage to identify potential well pad locations. Our engineers and geologists then apply well spacing assumptions based on industry activity in analogous regions. A net location is calculated as a formula of a gross location multiplied by the ratio of net acreage over gross acreage. We then multiply this calculation by a pooling factor where appropriate. We generally assume minimum 5,000 laterals. Management uses these estimates to, among other things, evaluate our acreage holdings and formulate plans for drilling. A number of factors could cause the number of wells we actually drill to vary significantly from these estimates, including the availability of capital, drilling and production costs, oil and natural gas prices, lease expirations, regulatory approvals and other factors. Non-GAAP Financial Measures Legacy s management uses Adjusted EBITDA as a tool to provide additional information and a metric relative to the performance of Legacy s business. Legacy s management believes that Adjusted EBITDA is useful to investors because this measure is used by many companies in the industry as a measure of operating and financial performance and is commonly employed by financial analysts and others to evaluate the operating and financial performance of Legacy from period to period and to compare it with the performance of our peers. Adjusted EBITDA may not be comparable to a similarly titled measure of such peers because all entities may not calculate Adjusted EBITDA in the same manner. Adjusted EBITDA should not be considered as an alternative to GAAP measures, such as net income, operating income, cash flow from operating activities or any other GAAP measure of financial performance. Our reference to PV-10 is numerically equivalent to the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC. 2

3 Legacy at a Glance Longstanding Midland, Texas-based operator (NASDAQ: LGCY) Stable PDP footprint Q4 17 daily production of 48.3 MBoepd (41% liquids) (1) Underlying PDP decline rate of 11.9% (1)(2)(3) and PDP R/P of 9.4 years (1)(3) Significant horizontal potential in the Permian and East Texas Identified 588 gross (408 net) operated horizontal Permian drilling locations on 40,600 gross / 31,500 net acres, 92% of which is held by production Last 46 horizontal wells brought online have average IP30 rates of ~840 Boe/d Identified 258 gross (182 net) operated horizontal East Tx drilling locations on 40,000 gross / 30,000 net acres, representing about 18% of our 215,000 gross / 165,000 net acres in the area, targeting the Cotton Valley Sands and Bossier/Haynesville Shales Continued two-rig development plan yields 23 years of inventory (4) Permian Basin East Texas Rocky Mountain Mid-Continent Headquarters ND MT SD WY NE CO KS NM TX Note: Darker shading represents increased reserve concentration. OK Q4 17 Production by Region (1) Proved Reserves by Region (1)(3) Proved PV-10 by Region (1)(3) 28% 28% 2% 16% 2% 46% 25% 1% 37% 33% 65% 17% 48.3 MBoepd 176 MMBoe (166 MMBoe PDP) $1,150MM ($1,053MM PDP) (1) Pro forma to exclude contribution from the Texas Panhandle assets divestitures that closed on February 6, 2018 (the Panhandle Sale ). (2) Represents weighted average three-year PDP production decline rate. (3) Source: 2017 SEC reserve report, pro forma for the Panhandle Sale (SEC price of $51.31 and $3.07 for oil and gas, respectively) (the Reserve Report ). (4) Represents total identified horizontal locations divided by an assumed 18 wells per rig drilled per year. 3

4 2017 Review Oil Production Growth: Record annual production of 49.2 MBoe/d in Q4 17 representing a 23% QoQ increase in oil production and volumes at the high end of guidance LOE: $9.41 LOE per Boe in Q4, down 12% from Q4 16 JDA Success: Brought 5 new horizontal Permian wells online in Q4 17, representing 47 wells since commencement of the JDA program Ended the year with 21 DUCs, 20 of which we expect to bring online in Q1 18 via batch completions $141MM Acceleration Payment to TPG Sixth Street Partners (TSSP) and amending our JDA in August 2017 increased our exposure to our then-current wells and future development potential TSSP elected to participate in a second tranche of 26 wells plus 9 wells in the JDA s area of mutual interest; expect to spud final well in mid-2018 Asset Sales: Completed $23MM of asset sales in 2017 which relieved $8.4MM in P&A liabilities and negative LTM cash flow Completed an additional $27MM in divestitures YTD 18 including non-core PDP in the Texas Panhandle and acreage that we did not intend to drill Bolt-on Acquisitions: Completed $19MM of acquisitions adding 49 horizontal operated identified locations in the Permian and/or increasing our NRI in existing near-term drilling prospects Compressed Leverage Metrics: Reduced Pro Forma Total Debt / EBITDA by 2.1x in 2017 (1) Gained Additional GSO Investment and Achieved Voting Power in Notes: Repurchased $187MM of our 6.625% Senior Notes at $0.70, funded by draw from increased $400MM 2 nd Lien Term Loan Commitment; gained meaningful voting power in our Senior Notes and captured discount (1) Total Debt is as of February 21, EBITDA is LTM as of 12/31/17. Both figures are pro forma for the Panhandle Sale. See slide 15. 4

5 Operated Permian Horizontal Acreage with Identified Locations Northwest Shelf Total Acreage Gross Net 6,400 5,900 Midland Basin Total Acreage Gross Net 12,700 10,700 Delaware Basin Total Acreage Gross Net 10,600 7,800 Central Basin Platform Total Acreage Gross Net 10,900 7,200 Identified Locations Active Horizontal Rigs Total Acreage Gross Net Total 40,600 31,500 Source: Company data and estimates. Acreage statistics herein tie to identified, operated horizontal locations. See Annual Report for total acreage statistics. 5

6 Total Permian Acreage Northwest Shelf Midland Basin Delaware Basin Central Basin Platform Identified Locations Other Permian (Op + Non-Op) Active Horizontal Rigs Source: Company data and estimates. See Annual Report for total acreage statistics. 6

7 Operated Horizontal Development Inventory Legacy has identified attractive drilling locations by coordinating the efforts of its land, geology, operations and business development teams Legacy and industry activity within and around Legacy s acreage positions is also helping to de-risk these prospects Legacy s Reserve Report only includes 16 gross / 10 net operated horizontal PUDs Ongoing technical analysis suggests the addition of 830 gross (580 net) locations in its Permian and East TX core operating regions Operated Horizontal Drilling Locations - Permian and East Tx We lls PDP at YE'17 Total Identified Locations(1) per Gross Net Gross Net Section Permian Midland Basin Lower Sprayberry Wolfcamp Devonian Delaware Basin Brushy Canyon st Bone Spring nd Bone Spring rd Bone Spring Wolfcamp Central Basin Platform San Andres Northwest Shelf San Andres Yeso Abo / Wolfcamp Devonian Total Permian (2) East Texas Freestone Cotton Valley Sands Shelby Bossier + Haynesville Shales Total East Tx Total Source: Company data and estimates. (1) PUD locations contained in Reserve Report plus Identified Horizontal Locations (2) Spacing based on analogous, nearby development. 7

8 2018 Capital Budget Free cash flow neutral program drives projected 47% oil-production growth and 46% EBITDA growth YoY in 2018 Similar gross capital figures to 2017; net capital increase is driven by higher average working interest following the Acceleration Payment to TSSP Operational efficiencies drive capital efficiency Increased size of batch completions in areas with adequate infrastructure Obtained dedicated frac fleet Efficiencies offset by assumed capital increase driven by consumables, equipment rentals, labor and inflation Maintain potential to increase capital spending Goal to remain cash flow neutral / positive Likely to commence East Tx horizontal development or additional Permian delineation opportunities 2018 Net Capital by Category & Permian County Andrews 1% Reagan 3% Midland 6% Martin 16% $225MM Net ($345MM Gross) Operated Permian Hz Dev $190MM Workovers / Recompletions / Vertical Lea 32% Howard 31% Non-Op Hz Dev Facilities / Other 8

9 2018 Permian D&C Detail Permian D&C Capital by Bench $203MM Total Net Economics of Scale % of Capital Budget 12,500 Lateral Length by County 10,000 37% Bone Spring 42% Wolfcamp 7,500 ~7,400 Wtd. Avg. 5,000 20% Spraberry 2,500 1% San Andres Single well Multi-well $190MM ~95% multi-well drilling allows for optimized batch completions and leverages historical infrastructure investments Actively engaged in discussions to extend Midland Basin lateral lengths 9

10 Horizontal Permian Program Development Hz Wells Drilled by Qtr and County Hz Wells Brought Online by Qtr and County 39 drilled in brought online in Q1'18 Q2'18 Q3'18 Q4'18 Q1'18 Q2'18 Q3'18 Q4'18 Lea Howard Midland Martin Lea Howard Midland Martin Andrews Reagan Grand Total Andrews Reagan Grand Total 10

11 Projected Well Economics 2018 Forecasted Development Lateral Gross D&C Peak 30-Day County/Bench Length (Ft.) Cost ($MM) Rate (Boe/d) (MBOE) % Oil EUR Howard County Lwr. Spraberry 7,500-10,000 $6.4-$ %-85% Wolfcamp A 7,500-10,000 $6.6-$ , ,000 81%-86% Lea County 1st Bone Spring 5,000-7,500 $5.6-$ %-75% 2nd Bone Spring 5,000-7,500 $5.7-$ %-85% 3rd Bone Spring (1) 7,500 $6.8-$ %-84% Martin County Wolfcamp B 10,000 $8.2-$ %-82% Midland County Lwr. Spraberry 5,000 $5.5-$ %-78% Wolfcamp B 5,000 $5.5-$ %-78% EUR (1) Negatively impacted compared to historical results due to drilling of replacement wells with mechanical issues. 11

12 2018 Guidance vs. Historicals (1) (2) 2H'17 Actual Δ: '18E vs. 2H'17 ($ in thousands unless otherwise noted) Excl. Panhandle Sale 18E Range # % Production: Oil (Bbls/d) 15,819 19,000-21,400 4, % Natural Gas Liquids (Bbls/d) 2,464 1,875-2,075 (489) (19.9%) Gas (Mmcf/d) (1.4) (0.8%) Total (Boe/d) 46,688 47,875-52,808 3, % Weighted Average NYMEX Differentials: Oil (per Bbl) ($3.22) ($4.00) - ($3.25) NGL realization (3) 55% 52% - 63% Natural gas (per Mcf) ($0.27) ($0.35) - ($0.20) Expenses: Lease operating expenses (4) $80,509 $175,000 - $195,000 $23, % Ad valorem and production taxes (% of revenue) 6.84% 7.40% % Cash G&A expenses (5) $18,267 $34,000 - $38,000 ($534) (1.5%) Adjusted EBITDA (6) $138,612 $300,000 - $360,000 $52, % (1) Pro forma to exclude contribution from the Panhandle Sale. (2) 18E based on mid-point of range. 2H 17 actuals annualized where appropriate. (3) Represents the projected percentage of assumed WTI crude oil prices. (4) Excludes ad valorem and production taxes. (5) Consistent with our definition of Adjusted EBITDA, these figures exclude LTIP and transaction-related expenses. (6) Adjusted EBITDA is a Non-GAAP financial measure. This measure does not include pro forma adjustments permitted under our credit agreements relating to acquired and divested oil or gas properties. A reconciliation of this measure to the nearest comparable GAAP measure is available on our website. Note: Figures above assume NYMEX strip pricing at 2/15/2018 (2018 Avg Oil $59.59 / $2.80 Gas) 12

13 Summary Financial Projections Projected Adjusted EBITDA growth driven by an 47% increase in oil production while maintaining free cash flow neutrality Oil Production (mbopd) Adjusted EBITDA ($MM) (1) $ % % 300 $ $ $ E E Capital Expenditures ($MM) (2) Adjusted EBITDA less Capex ($MM) (1) $ $177 $ $ $ E E (1) Adjusted EBITDA is a Non-GAAP financial measure. This measure does not include pro forma adjustments permitted under our credit agreements relating to acquired and divested oil or gas properties. A reconciliation of this measure to the nearest comparable GAAP measure is available on our website. (2) References development capital which specifically excludes acquisitions. Source: Mid-point of guidance per February 21, 2018 earnings release. 13

14 Transition Steps Taken & Completed Legacy has taken and is taking several proactive steps to position the Company to profitably generate material production and Adjusted EBITDA growth and develop its sizeable inventory of identified horizontal development locations Goal Description Achieved Build Production Growth Program Successfully built the backbone of a technical operations and development team with horizontal expertise that is scalable to a much larger drilling and completion program Poised to accelerate development of inventory The horizontal East Texas program will add significant natural gas production growth that will also fuel value accretion of associated Legacy-owned midstream assets Capture More Permian Hz Opportunities Control Costs Protect and Grow PDP Cash Flows Rationalize Portfolio Current Ambitions Leverage / Structure Accelerate Development to Capture Upside Dramatically increased our share of the existing and future development under the JDA with TSSP by making a $141 million Acceleration Payment and amended the JDA Leveraged our specific knowledge, experience and local presence to make select, discreet acquisitions totaling $15 million since 1/1/17 that increase ownership, extend planned laterals, add nearby locations, or otherwise increase our identified horizontal locations Continue to work with industry players to execute trades to enhance our interests in near-term development opportunities at the expense of other, less-desirous tracts LOE per Boe declined by 44% since 2014 and is projected to be ~$10 per Boe in 2018, consistent with 2H 17 Programmatic reduction in drilling days and batch completions continue to reduce D&C costs Significant, low-decline base supports balance sheet and fuels growth initiatives Remain a successful acquirer and operator of PDP assets Approximately 64% and 59% of 2018 oil and gas production is hedged (1) ; currently pursuing 2019 oil swaps Sell assets that do not exhibit i) growth potential or ii) sufficient cash flow profile Sold a negative cash flow CO2 Flood property. Eliminated significant P&A liability and a large CO2 purchase contract for 25% of the remaining liability. Sold several disjointed, negative cash flow properties with large P&A liability Sold Panhandle asset, an asset with a very high well count and low average daily rate with no growth potential and large P&A liability Other potential opportunities identified Evaluate and opportunistically pursue alternatives to change our legal structure and tax status as a partnership, materially reduce our outstanding debt and extend our near term maturity debt December repurchase from Fir Tree funded with GSO 2nd Lien provided meaningful voting power in our Senior Notes and captured discount Depending on the availability of cash flows, accelerating development of high-return, identified horizontal drilling locations within existing Permian and East Texas acreage (1) See slide

15 Balance Sheet Progress YE'16 YE'17 PF (1) Chg Revolving credit facility due 2019 $463.0 $ % 2nd Lien Term Loan due % Senior Notes due % Senior Notes due Total Debt $1,188.6 $1,319.2 Borrowing Base $600.0 $575.0 Liquidity (2) nd Lien Commitments $300.0 $400.0 Remaining 2nd Lien Availability (3) Credit Statistics: LTM PF Adj. EBITDA $155.8 $240.8 Revolver / EBITDA 3.0x 2.1x (0.9x) Secured Debt / EBITDA 3.4x 3.5x 0.1x Total Debt / EBITDA 7.6x 5.5x (2.1x) $600 $500 $400 $300 $200 $100 Debt Maturities $502 $339 $233 $ Apr 2019 Dec 2020 Aug 2021 Dec 2021 Revolving Credit Facility (4) 2nd Lien Term Loan Senior Notes Using the mid-point of our guided 2018E EBITDA (5) and capital budget ranges, we project exiting YE 18 with a Total Debt / EBITDA of ~4.0x We are evaluating and will opportunistically pursue alternatives to materially reduce our outstanding indebtedness and extend our near-term maturing indebtedness (1) Total Debt is as of February 21, EBITDA is LTM as of 12/31/17. Both figures are pro forma for the Panhandle Sale. (2) Reduced by $1.9MM and $0.8MM in outstanding letters of credit and increased by $2.0MM and $1.2MM in cash at YE 16 and YE 17, respectively. (3) $400MM facility allows $61MM of incremental funds available through October 25, (4) Excludes the Springing maturity date of August 1, 2020, if greater than or equal to $15MM of Senior Notes is outstanding on July 1, (5) Adjusted EBITDA is a Non-GAAP financial measure. This measure does not include pro forma adjustments permitted under our credit agreements relating to acquired and divested oil or gas properties. A reconciliation of this measure to the nearest comparable GAAP measure is available on our website. 15

16 Asset Detail 16

17 Lea County Recent Activity Update Legacy has generated strong well results in recent wells drilled in Lea County and continues to identify attractive drilling locations Assets include 3,200 gross (2,307 net) acres Average 30-day IP Rates realized since JDA commencement: 3rd Bone Spring 910 Boe/d 2nd Bone Spring 706 Boe/d 1st Bone Spring 831 (2) Boe/d Acreage Position and Legacy / Offset Hz Activity Inventory Zone PDP Locations Total 1 st Bone nd Bone rd Bone Upper Wolfcamp Lower Wolfcamp Total Source: Company data and estimates. (1) Includes 2 wells, one of which lost 2/3 of its lateral due to an incident, resulting in lost production. 17

18 Lea County Offset Wolfcamp Development Activity by Legacy and offset operators in the area has extended the Wolfcamp play to Northern Lea County. Oil on Pits Lower Wolfcamp 3 rd BS Landing / Wolfcamp Frac MTDR Airstrip RN #201H 24/IP 926 BOEPD XEC Lea 7#1H 30/IP 894 BOEPD CXO Blue Jay Fed #1H 30/IP 1,904 BOEPD Strong correlation zone to zone CXO Blue Jay Fed Com #2H 30/IP 1,694 BOEPD LGCY #62H 30/IP 1,378 BOEPD LGCY #59H 30/IP 1,404 BOEPD EOG Della 29 Federal Com 701H 30/IP 1,231 BOEPD Chisolm Lea South 25 Fed Com WCA #12H Drilling Complete CXO Mas Fed #4H 30/IP 1,288 BOEPD CXO Mas Fed #1H&2H APD Filed Source: Company data and estimates, DI Desktop. 18

19 Howard County Recent Activity Update Legacy has increased its acreage position in Howard County by 116%, or 1,848 acres net acres, since it started drilling in the area in 2015 Assets include 4,118 gross (3,441 net) acres Average 30-day IP Rates realized since JDA commencement: Wolfcamp A 910 Boe/d Lwr Spraberry 891 Boe/d Acreage Map Inventory (1) Zone PDP Locations Total Lower Spraberry Wolfcamp A Total Martin Borden Increased number, length and working interest in drilling locations through leasing, acreage swaps and acquisitions Ongoing, active swap discussions with nearby operator offers upside to current location count Midland Glasscock Original Properties 2015 Acquisition 2016 Acquisitions (Light = Non-op) 2017 Acquisitions (Light = Non-op) Lower Spraberry Wolfcamp A 1 Mile Well-Spacing Diagram (1) Source: Company data and estimates. (1) Does not include potential upside from Upper/Middle Spraberry. 19

20 Andrews County Horizontal San Andres Position Acreage Map Forge/Lime Rock Fisher 76C #6H 366 BOPD 30/IP; 564 MBOE EUR Ring Univ. 14Q#1H; 535 BOPD 30/IP Ector Midland Legacy s position in the area comprises 10,886 gross / 7,166 net acres and 106 gross / 60 net drilling locations that have been de-risked by successful operators in the area Legacy s Engineering and Operations professionals have significant experience in the area managing producing wells, waterflood and recompletion programs Development plan requires very little infrastructure investment, leveraging Legacyowned SWD assets Lime Rock Univ. 13 #4414H; 514 BOPD MCF 24 /IP Pacesetter Welborn 20#1H 236 BOPD 30/IP; 344 MBOE EUR Pacesetter Univ. JV 14#3H 856 BOPD 30/IP; 925 MBOE EUR Source: Company data, DI Desktop, IHS. 20

21 East Texas Summary Overview of Horizontal Inventory Freestone Area 31 vintage Hz Cotton Valley sand wells were completed using outdated D&C techniques 31 well averages Average lateral length of 2,885 Average EUR of 6.5 Bcf Average 2.3 Bcf / 1, identified drilling locations Longer laterals Modern completions and staging Midstream control enhances economics Shelby Area Well-positioned in Shelby Trough Latest completions with modern sand loadings averaged 2.1 Bcf / 1,000 Legacy has 19,129 gross / 12,641 net unitized acres held by production 12 units (~81% of net acres) are >70+% WI Currently permitting 6 locations Gathering & processing contracts are in place Areal View of East Texas Horizontal Prospects Shelby Area Bossier & Haynesville Shale Hz Prospect 188 locations Freestone Area Bossier Sand Hz Prospect 70 locations Source: Company data and estimates. 21

22 Appendix 22

23 Ongoing Expense Control Legacy has proactively cut expenses by 44% since 2014 driven by coordinated efforts at all levels of the organization to deliver value to all stakeholders through the downturn LOE per Boe Since 2011 $25.00 $20.00 $18.37 $19.08 $19.89 $18.98 LOE per Boe has declined by 44% from 2014 through 2017 and is projected to be approximately $10 in 2018 $ / Boe $15.00 $10.00 $13.03 $10.77 $10.58 ~ $10.00 $ E Source: Company filings and management estimates. 23

24 Hedge Summary + Price Sensitivities Added 1,000 Bbls/d of 2018 oil swaps at $63.68 year-to-date Currently working to add 2019 oil swaps % Oil Hedged (1) % Natural Gas Hedged (1) 70% 60% 64% 70% 60% 59% 50% 40% 30% 20% 50% 40% 30% 20% 42% 10% 0% 0% Set forth below are the effective oil and gas prices (before the impacts of differentials) and after the impact of hedges (1) : 10% 0% Avg WTI Oil Price Effective Oil Price Effective Gas Price $40 $48.02 $40.00 $2.50 $2.93 $2.86 $50 $52.23 $50.00 $2.75 $3.03 $3.00 Avg. Henry Hub Gas Price $60 $57.90 $60.00 $3.00 $3.13 $3.15 $70 $61.81 $70.00 $3.25 $3.24 $3.30 (1) Figures based on mid-point of 2018 guidance. 24