Q E a r n i n g s. M a y 3, 2018

Transcription

1 Q E a r n i n g s M a y 3, 2018

2 FORWARD-LOOKING STATEMENTS Except for historical information contained herein, the statements in this presentation are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer s actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, completion of planned divestitures, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to perform the Company s drilling and operating activities, access to and availability of transportation, processing, fractionation, refining and export facilities, Pioneer s ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer s credit facility, investment instruments and derivative contracts and purchasers of Pioneer s oil, natural gas liquid and gas production, uncertainties about estimates of reserves and resource potential, identification of drilling locations and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impacts of climate change, cybersecurity risks, ability to implement planned stock repurchases, the risks associated with the ownership and operation of the Company s industrial sand mining and oilfield services businesses and acts of war or terrorism. These and other risks are described in Pioneer s Annual Report on Form 10-K for the year ended December 31, 2017, and other filings with the Securities and Exchange Commission. In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. Pioneer undertakes no duty to publicly update these statements except as required by law. Please see the Supplemental Slides included in this presentation for other important information. 2

3 HIGHLIGHTS Q adjusted income: $284 MM, or $1.66 per diluted share 1 Q Permian Basin production: 260 MBOEPD At top end of guidance range of 252 MBOEPD to 260 MBOEPD Increase of 9 MBOEPD, or 3%, vs. Q Freezing temperatures in early January resulted in a production loss of ~6 MBOEPD for Q1 Q1 Permian Basin oil production: 170 MBOPD Placed 63 wells on production in Q1 Q total Company production: 312 MBOEPD Near top end of guidance range of 304 MBOEPD to 314 MBOEPD Increase of 7 MBOEPD, or 2%, vs. Q In addition to the Permian Basin weather impact, Q1 production was negatively impacted by 2 MBOEPD due to a compressor station fire in the West Panhandle field o West Panhandle production resumed at ~8 MBOEPD in early April Strong quarter-end balance sheet with $1.8 B of cash on hand 2 Net debt to forecasted 2018 operating cash flow of 0.3x and net debt-to-book capitalization of 7% 3 1) Adjusted income and adjusted income per diluted share amounts are non-gaap financial measures. See reconciliation in Supplemental Slides 2) Includes liquid investments 3) Based on current strip prices for the remainder of the year of $66/BBL for oil and $2.80/MCF for gas 3

4 HIGHLIGHTS (CONT.) Firm transportation (FT) contracts in place to assure movement of Pioneer s increasing volumes of oil and gas production out of the Permian Basin Delivered ~160 MBOPD of Permian Basin oil to the Gulf Coast under firm pipeline contracts during Q1; 87 MBOPD exported ~75% of Pioneer s Permian Basin gas production of 216 MMCFPD is sold under firm pipeline contracts to the southern California market; remainder sold primarily at Waha under term contracts Premiums on Gulf Coast refinery and export sales added $16 MM of incremental cash flow in Q1 Closed sale of 10,200 net acres in the Eagle Ford Shale for $103 MM 2018 executive compensation program revised to incorporate return on capital employed (ROCE) 1 and per-share production and proved reserves growth targets Repurchased ~$17 MM of common stock in Q1 Purchased under the Company s $100 MM authorized program; intended to offset dilution from annual employee stock awards 1) Return on Capital Employed is a non-gaap financial measure. See Supplemental Slides 4

5 2018 UPDATE Continuing to operate 20 horizontal rigs in the Permian Basin Expecting to POP wells during 2018 Drilling the most productive, high-return wells in the Basin Cash operating margins and IRRs continue to be strong Evaluating the timing of rig additions later in 2018 to support 2019 plan On track to place ~45 Version 3.0+ completions on line during 1H 2018 as planned Version 3.0+ completions to date continue to significantly outperform Version 3.0 o Completed 31 Version 3.0+ wells in Q1; placed 16 Version 3.0+ wells on production Evaluating the number of Version 3.0+ completions to be added in 2H 2018 Planning to appraise 3 additional Wolfcamp D wells with Version 3.0 completions during 2018 First Wolfcamp D well with this type of completion (placed on production during Q4 2017) has delivered 130-day cumulative production of 260 MBOE (72% oil) Expect to appraise 19 wells in the Middle Spraberry Shale, Jo Mill and Lower Spraberry Shale during 2018 to determine the optimal long-term development strategy 5

6 NYMEX Gas Price ($/MCF) 2018 UPDATE (CONT.) Progressing divestiture process for Eagle Ford, South Texas, Raton and West Panhandle assets, making Pioneer a Permian Basin pure play After all of the divestitures are completed, reported cash operating margins and corporate returns will be significantly improved 2018 capital spending to be funded from forecasted cash flow of ~$3.2 B at current strip prices for the remainder of the year 2018 capital budget of $2.9 B expected to be increased due to additional Version 3.0+ completions, late-year rig additions preparing for 2019 and inflation 2018 Permian production growth continues to be forecasted at 19% - 24%; trending to the high end of the range Repaid May debt maturity of $450 MM from cash on hand 2018 Cash Flow Sensitivity to Forward Commodity Prices ($ MM) (Permian Basin) NYMEX Oil Price ($/BBL) Based on current strip pricing for remainder of the year of $66/BBL oil & $2.80/MCF gas 6

7 36 VERSION 3.0+ COMPLETIONS SHOWING STRONG RESULTS Northern Midland Basin: LSS Cumulative Production (MBOE) Version 3.0+: 3 wells ~9,000 avg. lateral length Days on Production Southern Upton and Reagan: Wolfcamp B Cumulative Production (MBOE) 1 Version 3.0+: 5 wells ~10,000 avg. lateral length Days on Production 1) Production normalized for shut-ins 2) Cumulative production normalized to a lateral length of 9,700 Updated Late April Version 3.0: 27 wells since late-2015 ~8,700 avg. lateral length Updated Late April Version 2.0: 7 wells since late-2015 ~9,600 avg. lateral length Central Midland Basin: Wolfcamp B Cumulative Production (MBOE) Version 3.0+: 12 wells ~9,700 avg. lateral length Version 3.0: 16 wells since 2016 ~9,200 avg. lateral length Updated Late April Days on Production Pembrook and Giddings: Wolfcamp B Cumulative Production (MBOE) 1 Version 3.0+: 16 wells ~8,300 avg. lateral length 2 Updated Late April Version 3.0: 30 wells since mid-2016 ~9,700 avg. lateral length Days on Production 7

8 PERMIAN BASIN PRODUCTION GROWTH FORECAST Permian Basin Net Production MBOPD MBOEPD >1 MMBOEPD >700 MBOPD Oil (MBOPD) Q1 Q2 Q3 Q4 2026E 2018E 8

9 PIONEER S TEMPLATE FOR ENHANCING SHAREHOLDER VALUE FOCUS ON RETURNS: Low-cost, high-return Permian wells underpin increasing corporate returns CAPITAL DISCIPLINE: Capital program within cash flow drives strong production growth RETURN OF CAPITAL: Increasing free cash flow 1 generation leads to return of capital to shareholders PRESERVE STRONG BALANCE SHEET: Maintain low leverage ratios to provide financial flexibility HIGHLY REPEATABLE PROGRAM: Decades of low-risk drilling inventory with cash flow breakeven oil prices 1 that decrease annually Permian Basin drilling provides high return on capital and leads to increasing return of capital 1) See Supplemental Slides for definition of financial metrics 9

10 FIRM TRANSPORTATION TO THE GULF COAST INSULATES PIONEER FROM MIDLAND BASIS DIFFERENTIAL Sales Volumes to Gulf Coast (MBOPD) 1 ~160 Midland Houston Corpus Christi Nederland ~115 ~80 ~55 ~ Q1 '17 Q2 '17 Q3 '17 Q4 '17 Q1 '18 Gulf Coast Refinery Sales Exports Currently delivering ~160 MBOPD of Permian Basin net oil production to the Gulf Coast under firm transportation contracts; represents ~95% of Pioneer s current Permian production Brent-related pricing premiums received on Gulf Coast refinery and export sales added $16 MM of incremental cash flow in Q1 Exported 87 MBOPD during Q1; similar volume anticipated in Q2 Expect exports to grow during 2H as Pioneer increases its export capacity from ~110 MBOPD to ~150 MBOPD Targeting >90% of long-term Permian Basin net oil production under firm pipeline transportation to the Gulf Coast for refinery sales and exports Volumes under firm transportation contracts increases through 2021 commensurate with forecasted production growth 1) Q through Q exclude exports from Corpus Christi 10

11 WELL POSITIONED TO MOVE PERMIAN GAS PRODUCTION SoCal Waha Midland Gulf Coast Express Pipeline Agua Dulce Exports to Mexico Refining & Petchem Markets LNG Exports ~75% of Pioneer s Permian Basin net gas production of 216 MMCFPD is sold under firm pipeline contracts to the southern California market Current uplift of $0.60 per MCF Remainder sold primarily at Waha under term contracts Secured firm transport on Kinder Morgan s Gulf Coast Express Pipeline Access to LNG exports, refineries, petrochemical facilities and Mexican markets Expected to be on line at the end of Q Firm transportation and term contracts provide flow assurance for gas <5% of estimated 2018 total Permian oil, NGL and gas revenue derived from gas 11

12 Q EARNINGS SUMMARY $ Millions (After Tax) $ Per Diluted Share Net income attributable to common stockholders Noncash mark-to-market (MTM) derivative losses ($136 MM before tax) Income adjusted for noncash MTM derivative losses Q Guidance vs. Results Guidance Results of Operations Daily Production (MBOEPD) Production Costs Including Taxes ($/BOE) $ $9.00 $ Exploration & Abandonment ($ MM) $20 - $30 $35 3 DD&A ($/BOE) $ $14.50 $12.72 G&A ($ MM) $80 - $85 $90 4 Interest Expense ($ MM) $33 - $38 $36 Other Expense ($ MM) $60 - $70 $57 Accretion of Discount on ARO ($ MM) $4 - $7 $4 Current Income Tax Provision (Benefit) ($ MM) <$5 $ - Effective Tax Rate (%) 21% - 25% 22% 1) Non-GAAP financial measure. See reconciliation in Supplemental Slides 2) Reflects adoption of new revenue recognition standard that requires gas processing fees and associated downstream fractionation and transportation fees to be recognized as an expense in production costs versus prior treatment under which these costs were recognized as a reduction in NGL and gas revenue 3) Includes $10 MM of front-end loaded seismic expense for new 3-D surveys in the Permian Basin 4) Includes $2 MM of accelerated amortization on 2018 stock awards due to changes in the Company s retirement benefits 12

13 NEW REVENUE RECOGNITION STANDARD The Company adopted the new revenue recognition standard (Accounting Standards Update No , (ASC 606) Revenue from Contracts with Customers ) effective January 1, 2018 Under the new rule, gas processing fees and associated downstream fractionation and transportation fees that were previously reflected as a reduction in the Company s reported NGL and gas revenues are now required to be recognized as an expense in the Company s production costs As a result of this change, reported NGL and gas revenues and associated price realizations will be higher, with an equivalent offsetting increase in production costs Adoption of this new rule results in no change to the Company s cash operating margins Q Accounting Change Reconciliation 1 Reporting Prior to Accounting Change New Reporting Basis (as of Q1 2018) Effect of Change $ MM per BOE except as indicated $ MM per BOE except as indicated $ MM per BOE except as indicated Oil and Gas Sales Oil sales $ 1,013 $ per Bbl $ 1,013 $ per Bbl $ - $ - per Bbl NGL sales per Bbl per Bbl per Bbl Gas sales per Mcf per Mcf per Mcf Oil and gas sales $ 1,223 $ $ 1,266 $ $ 43 $ 1.53 Production Costs $ 170 $ 6.07 $ 213 $ 7.60 $ 43 $ 1.53 Production Taxes $ 2.70 $ 2.70 $ - Q1 Cash Margin $ $ $ - New accounting rule is cash operating margin neutral 1) See Supplemental Slides for the pro forma effect of the accounting change on 2017 as if ASC 606 had been applied to prior periods 13

14 PRICE REALIZATIONS Realized Prices NYMEX calendar month average Q1'17 Q2'17 Q3'17 Q4'17 Q1'18 Q1'17 Q2'17 Q3'17 Q4'17 Q1'18 Q1'17 Q2'17 Q3'17 Q4'17 Q1'18 Oil ($/BBL) NGL ($/BBL) Gas ($/MCF) NYMEX differential (2.87) (3.28) (2.85) (2.59) (1.23) (27.63) (26.60) (23.49) (27.87) (35.13) (0.28) (0.33) (0.15) (0.16) (0.42) Realized prices Derivatives not included in price (4.49) (0.27) (0.03) Price including derivatives Realized NGL prices, excluding derivatives, as a percentage of NYMEX oil calendar month average 47% 45% 51% 50% 44% 1) Prior period NGL and gas realized prices have been adjusted pro forma for adoption of ASC 606. This is a non- GAAP financial measure. See reconciliation in Supplemental Slides 2) Represents cash settlements recorded in net derivative gains or losses; excludes liquidated derivatives 14

15 PRODUCTION COSTS 1 (PER BOE) Workovers Production & Ad Valorem Taxes Gathering, Processing & Transportation LOE $10.30 $9.69 $9.70 $9.63 $9.09 $0.82 $0.59 $0.76 $1.02 $0.78 $2.11 $2.19 $2.70 $2.10 $2.23 $2.28 $2.13 $2.32 $2.47 $2.29 $4.99 $4.79 $4.48 $4.14 $4.41 Q compared to Q4 2017: Increase in LOE primarily driven by labor costs, fuel and hot oil rates Production taxes higher due to increase in oil prices Natural Gas Processing ($0.28) ($0.18) ($0.29) $(0.34) $(0.10) Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 1) Prior period production costs have been adjusted pro forma for adoption of ASC 606. This is a non-gaap financial measure. See reconciliation in Supplemental Slides 15

16 LIQUIDITY POSITION Net debt at the end of Q (reflects cash on hand, including liquid investments, of $1.8 B) Unsecured credit facility availability Net debt-to-book capitalization at the end of Q1 $0.9 B $1.5 B 7% Maturities and Balances $450 MM 7.500% $500 MM 3.450% $600 MM 3.950% $500 MM 4.450% $250 MM 7.200% $1.5 B unsecured credit facility (undrawn as of 3/31/18) Repaid May debt maturity of $450 MM from cash on hand Net debt to 2018E operating cash flow of 0.3x Mid-investment grade rated by Moody s, S&P and Fitch 1) Excludes issuance costs and issuance discounts of ~$16 MM 16

17 Q GUIDANCE Daily Production (MBOEPD) Guidance Total Corporate Permian Basin Production Costs ($/BOE) $10.00 $12.00 Exploration & Abandonment ($ MM) $20 $30 Drilling and Acreage $5 - $10 Personnel and Seismic $15 - $20 DD&A ($/BOE) $12.50 $14.50 G&A ($ MM) $90 $95 Interest Expense ($ MM) $30 $35 Other Expense ($ MM) 1 $60 $70 Accretion of Discount on ARO ($ MM) $4 $7 Current Income Taxes ($ MM) $0 $5 Effective Tax Rate (%) 21% 25% 1) Other expense includes $40 MM to $45 MM of expected charges associated with excess firm gathering and transportation commitments 17

18 SUPPLEMENTAL SLIDES 18

19 PRODUCTION BY COMMODITY Q1 '17 Q2 '17 Q3 '17 Q4 '17 Q1 '18 Midland Basin Oil (BOPD) 104, , , , ,628 Horizontal NGL (BOEPD) 26,709 32,546 37,923 40,895 45,718 Gas (MCFPD) 128, , , , ,987 Total (BOEPD) 152, , , , ,343 Midland Basin Oil (BOPD) 29,819 27,279 25,490 25,816 25,192 Vertical NGL (BOEPD) 9,820 9,630 9,755 8,933 8,678 Gas (MCFPD) 50,456 48,453 39,266 39,034 35,999 Total (BOEPD) 48,048 44,984 41,789 41,255 39,871 Total Midland Basin Oil (BOPD) 134, , , , ,820 NGL (BOEPD) 36,529 42,176 47,678 49,828 54,396 Gas (MCFPD) 178, , , , ,986 Total (BOEPD) 200, , , , ,214 Assets Being Divested Oil (BOPD) 11,097 9,577 9,373 13,661 12,699 NGL (BOEPD) 10,299 11,092 9,668 12,567 11,785 Gas (MCFPD) 160, , , , ,883 Total (BOEPD) 48,066 46,519 44,347 53,477 51,631 Total Operations Oil (BOPD) 145, , , , ,519 NGL (BOEPD) 46,829 53,267 57,346 62,396 66,181 Gas (MCFPD) 338, , , , ,869 Total (BOEPD) 248, , , , ,845 19

20 PRODUCTION BY COMMODITY (ASSETS BEING DIVESTED) Q1 '17 Q2 '17 Q3 '17 Q4 '17 Q1 '18 Eagle Ford Oil (BOPD) 7,870 6,279 6,956 9,896 9,010 NGL (BOEPD) 6,800 6,490 6,981 8,280 8,178 Gas (MCFPD) 45,069 39,531 40,775 50,755 48,849 Total (BOEPD) 22,182 19,359 20,734 26,634 25,331 Raton Oil (BOPD) NGL (BOEPD) Gas (MCFPD) 89,959 89,228 88,490 86,352 83,505 Total (BOEPD) 14,993 14,871 14,748 14,392 13,917 West Panhandle Oil (BOPD) 1,997 2,061 1,181 1,449 1,368 NGL (BOEPD) 3,344 4,371 2,466 3,786 3,091 Gas (MCFPD) 5,390 7,936 5,266 11,302 11,324 Total (BOEPD) 6,240 7,755 4,525 7,119 6,346 South Texas Oil (BOPD) 1,226 1,230 1,235 2,306 2,312 NGL (BOEPD) Gas (MCFPD) 19,565 18,346 17,225 15,039 19,155 Total (BOEPD) 4,641 4,517 4,325 5,313 6,019 Other Oil (BOPD) NGL (BOEPD) Gas (MCFPD) Total (BOEPD) Assets Being Divested Oil (BOPD) 11,097 9,577 9,373 13,661 12,699 NGL (BOEPD) 10,299 11,092 9,668 12,567 11,785 Gas (MCFPD) 160, , , , ,883 Total (BOEPD) 48,066 46,519 44,347 53,477 51,631 20

21 CASH MARGINS BY ASSET Q Cash Margin by Asset ($ per BOE) Permian Horizontals Permian Verticals Eagle Ford Other Assets Total Company Realized price (ex-derivatives) 1 $ $ $ $ $ ,2 Production costs (4.18) (19.93) (12.18) (13.05) (7.60) Production and ad valorem taxes (2.95) (2.97) (1.63) (1.27) (2.70) Cash margin $ $ $ $ 9.66 $ % Oil 66% 63% 36% 14% 59% 1) Reflects adoption of new revenue recognition rule; see New Revenue Recognition Standard slide for a description of the impact of adopting the new rule 2) Includes lease operating expense, gathering, processing and transportation, workover expense and net natural gas processing cost 21

22 LOW-COST, HIGH-RETURN PERMIAN BASIN HORIZONTAL WELLS UNDERPIN PIONEER S 10-YEAR PLAN Pioneer s 2017 Permian Basin Horizontal Cost Structure ($/BOE) Low-Cost, High-Return Permian Basin Horizontal Wells $1.54 $3.28 ~$19 $9.40 $4.46 Grow Corporate ROCE 2 Annually Grow Cash Flow Annually; Generate Free Cash Flow 2 by 2020 at ~$50 Decrease Cash Flow Breakeven Oil Price 2 Annually Proved Developed F&D Production Costs and Taxes G&A 1 Interest Expense 1 Total Cost Pioneer s 10-Year Growth Target >700 MBOPD in 2026 >1 MMBOEPD in ) Reflects Pioneer s average G&A and interest expense on a total Company BOE basis for ) Refer to Definitions slide in Supplemental Slides for definition of financial metrics 22

23 10-YEAR PLAN: SIGNIFICANTLY IMPROVING FINANCIAL METRICS 1,2,3 Cash Flow ($B) >$11 ~$58 4 Cash Flow Breakeven Oil Price ~$50 ~$40 ~$ % Return on Capital Employed 5 15% Drilling low-cost, highly productive wells that generate high rates of return as a result of a low all-in cost structure of ~$19 per barrel Drilling program delivers robust cash flow growth that self-funds capital program, improves corporate ROCE and generates free cash flow 1) Based on $55 oil and $3 gas with no derivatives beginning in ) Assumes no improvement in efficiencies or well productivity from YE ) Refer to Definitions slide in Supplemental Slides for definition of financial metrics 4) Assumes capital spending of $2.9 B 5) Return on Capital Employed is a non-gaap financial measure. Refer to Supplemental Slides 23

24 OPEN COMMODITY DERIVATIVE POSITIONS AS OF 5/1/18 Oil Q Q Q Collars (BPD) 3,000 3,000 3,000 - NYMEX Short Call Price ($/BBL) $58.05 $58.05 $58.05 $ - NYMEX Put Price ($/BBL) $45.00 $45.00 $45.00 $ - Three Way Collars (BPD) 1 149, , ,000 65,000 NYMEX Call Price ($/BBL) $57.79 $57.70 $57.62 $60.74 NYMEX Put Price ($/BBL) $47.42 $47.34 $47.26 $52.69 NYMEX Short Put Price ($/BBL) $37.38 $37.31 $37.23 $42.69 Permian Basin Oil Coverage: >85% in 2018 and >30% in ) When NYMEX price is above call price, Pioneer receives call price. When NYMEX price is between put price and call price, Pioneer receives NYMEX price. When NYMEX price is between the put price and the short put price, Pioneer receives put price. When NYMEX price is below the short put price, Pioneer receives NYMEX price plus the difference between the put price and short put price 24

25 OPEN COMMODITY DERIVATIVE POSITIONS AS OF 5/1/18 Ethane Q Q Q Frac Spread (BPD) 1 2,500 2,500 2,500 2,500 MMBTUPD Equivalent 6,920 6,920 6,920 6,920 Price differential to NYMEX ($/MMBTU) $1.60 $1.60 $1.60 $1.60 Permian Basin NGL Coverage: <5% in 2018 and )Represent basis swap contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The basis swaps fix the basis differential on a NYMEX Henry Hub ("HH") MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane 25

26 OPEN COMMODITY DERIVATIVE POSITIONS AS OF 5/1/18 Gas Q Q Q Swaps (MMBTUPD) 1 100, , ,000 - NYMEX Price ($/MMBTU) $3.00 $3.00 $3.00 $ - Three Way Collars (MMBTUPD) 1,2 50,000 50,000 50,000 - NYMEX Call Price ($/MMBTU) $3.40 $3.40 $3.40 $ - NYMEX Put Price ($/MMBTU) $2.75 $2.75 $2.75 $ - NYMEX Short Put Price ($/MMBTU) $2.25 $2.25 $2.25 $ - Permian Basin Gas Basis Swaps Q Q Q Southern California (MMBTUPD) 3 40,000 80,000 66,522 84,932 Price Differential to NYMEX ($/MMBTU) $0.30 $0.30 $0.50 $0.33 Permian Basin (MMBTUPD) 4-50,000 50,000 37,397 Price Differential to NYMEX ($/MMBTU) $ - $ (1.50) $ (1.50) $ (1.50) Permian Basin Gas Coverage: >60% in )Represents the NYMEX Henry Hub index price or approximate NYMEX price based on historical differentials to the index price at the time the derivative was entered into 2)When NYMEX price is above call price, Pioneer receives call price. When NYMEX price is between put price and call price, Pioneer receives NYMEX price. When NYMEX price is between the put price and the short put price, Pioneer receives put price. When NYMEX price is below the short put price, Pioneer receives NYMEX price plus the difference between the put price and short put price 3)The referenced basis swap contracts fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California 4)The referenced basis swap contracts fix the basis differentials between the index price at which the Company sells a portion of its Permian Basin gas and the NYMEX index price used in swap contracts and collar contracts with short puts 26

27 2017 EFFECT OF NEW REVENUE RECOGNITION STANDARD The adoption of ASC 606 was effective January 1, 2018, this chart illustrates the pro forma effect of the accounting change as if ASC 606 had been effective for Q Q Q Q $ MM per BOE except as indicated $ MM per BOE except as indicated $ MM per BOE except as indicated $ MM per BOE except as indicated Reporting Prior to Accounting Change: Oil sales $ 643 $ per Bbl $ 602 $ per Bbl $ 674 $ per Bbl $ 873 $ per Bbl NGL sales per Bbl per Bbl per Bbl per Bbl Gas sales per Mcf per Mcf per Mcf per Mcf Oil and Gas Sales $ 809 $ $ 768 $ $ 855 $ $ 1,085 $ Production Costs Production Taxes Cash Margin $ 621 $ $ 570 $ $ 650 $ $ 872 $ Pro Forma impact of Accounting Change: Oil sales $ 643 $ per Bbl $ 602 $ per Bbl $ 675 $ per Bbl $ 874 $ per Bbl NGL sales per Bbl per Bbl per Bbl per Bbl Gas sales per Mcf per Mcf per Mcf per Mcf Oil and Gas Sales $ 838 $ $ 799 $ $ 894 $ $ 1,128 $ Production Costs Production Taxes Cash Margin $ 621 $ $ 570 $ $ 650 $ $ 872 $ New accounting rule is cash operating margin neutral 27

28 SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES EBITDAX and discretionary cash flow ( DCF ) are disclosed by Pioneer, and reconciled to the generally accepted accounting principle ( GAAP ) measures of net income and net cash provided by operating activities because of their wide acceptance by the investment community as financial indicators of a company s ability to internally fund exploration and development activities and to service or incur debt. The Company also views the non-gaap measures of EBITDAX and DCF as useful tools for comparisons of the Company s financial indicators with those of peer companies that follow the full cost method of accounting. EBITDAX and DCF should not be considered as alternatives to net income or net cash provided by operating activities, as defined by GAAP. ($ Millions) Q1 18 Net income $178 Depletion, depreciation and amortization 357 Exploration and abandonments 35 Accretion of discount on asset retirement obligations 4 Interest expense 36 Income tax provision 50 Gain on disposition of assets, net (4) Derivative related activity 136 Amortization of stock-based compensation 17 Other noncash items 20 EBITDAX 829 Cash interest expense (35) Discretionary cash flow 794 Cash exploration expense (28) Changes in operating assets and liabilities (212) Net cash provided by operating activities $554 28

29 SUPPLEMENTAL EARNINGS PER SHARE INFORMATION The Company uses the two-class method of calculating basic and diluted earnings per share. Under the two-class method of calculating earnings per share, GAAP provides that share and unit-based awards with guaranteed dividend or distribution participation rights qualify as participating securities during their vesting periods. During periods in which the Company realizes net income attributable to common shareholders, the Company s basic net income per share attributable to common stockholders is computed as (i) net income attributable to common stockholders, (ii) less participating basic earnings (iii) divided by weighted average basic shares outstanding and the Company s diluted net income per share attributable to common stockholders is computed as (i) basic net income attributable to common stockholders, (ii) plus the dilutive effect, if any, of participating securities (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a net loss attributable to common stockholders, securities or other contracts to issue common stock are dilutive to loss per share; therefore, conversion into common stock is assumed not to occur. The following table is a reconciliation of the Company s net income attributable to common stockholders to basic and diluted net income attributable to common stockholders for the three months ended March 31, 2018: ($ Millions) Q1 18 Net income attributable to common stockholders $178 Participating basic earnings (1) Basic and diluted net income attributable to common stockholders $177 (Shares in Millions) Weighted average common shares outstanding: Q1 18 Basic 170 Dilution attributable to stock based compensation 1 Diluted

30 SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES Adjusted income excluding noncash MTM derivative losses as presented in the Financial and Operating Highlights slide and in the Q Earnings Summary slide, is presented and reconciled to Pioneer s net income attributable to common stockholders (determined in accordance with GAAP) because Pioneer believes that this non-gaap financial measure reflects an additional way of viewing aspects of Pioneer s business that, when viewed together with its financial results computed in accordance with GAAP, provide a more complete understanding of factors and trends affecting its historical financial performance and future operating results, greater transparency of underlying trends and greater comparability of results across periods. In addition, management believes that this non-gaap measure may enhance investors ability to assess Pioneer s historical and future financial performance. This non-gaap financial measures is not intended to be a substitute for the comparable GAAP measure and should be read only in conjunction with Pioneer s consolidated financial statements prepared in accordance with GAAP. Noncash MTM derivative gains and losses will recur in future periods; however, the amount and frequency can vary significantly from period to period. The table below reconciles Pioneer s net income attributable to common stockholders for the three months ended March 31, 2018, as determined in accordance with GAAP, to the adjusted income excluding noncash MTM derivative losses for that quarter. $ Millions (After Tax) $ Per Diluted Share Net income attributable to common stockholders Noncash MTM derivative losses ($136 MM before tax) Income adjusted for noncash MTM derivative losses This presentation also contains a forward-looking non-gaap financial measure, return on capital employed. Due to its forward-looking nature, management cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measure, such as future noncash property impairments, gains or losses on future divestitures and future noncash MTM derivative gains and losses. Accordingly, Pioneer is unable to present a quantitative reconciliation of such forward-looking non-gaap financial measure to its most directly comparable forward-looking GAAP financial measure. Amounts excluded from this non-gaap measure in future periods could be significant. 30

31 DEFINITIONS Return on Capital Employed (ROCE) equals net income adjusted for tax-effected interest expense, net noncash MTM derivative gains and losses and other unusual items 1 divided by the summation of average equity plus average net debt Free Cash Flow (FCF) occurs when net cash provided by operations (before working capital changes) exceeds Capital Expenditures Cash Flow Breakeven Oil Price is the NYMEX WTI price at which net cash flow provided by operations (before working capital changes) equals Capital Expenditures Capital Expenditures equal the Company s planned capital budget for any year excluding acquisitions, asset retirement obligations, capitalized interest, geological and geophysical G&A and IT system upgrades 1) Unusual items have historically included noncash property impairments, gain/loss on asset divestitures and tax-related items 31

32 COMMON SHARE REPURCHASES The stock purchase program allows for up to $100 million of stock to be repurchased during Pioneer may repurchase shares from time to time at management s discretion in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. In addition, shares may also be purchased pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Securities Exchange Act of 1934, as amended, which would permit shares to be repurchased when the Company might otherwise be precluded from doing so under insider trading laws. The amount and timing of repurchases are subject to a number of factors, including stock price, trading volume and general market conditions, and the program may be modified, suspended or terminated at any time by Pioneer s Board of Directors. The Company intends to fund repurchases under the program from cash flow, proceeds from asset divestitures or cash and cash equivalents. 32