Fourth Quarter 2012 Earnings February 14, 2013 Exhibit 99.2 |
2 Forward-Looking Statements Except for historical information contained herein, the statements, charts and graphs in this presentation are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. 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 third parties on mutually acceptable terms, the receipt of approvals required to consummate the Company’s Southern Wolfcamp joint interest transaction, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to complete the Company's operating activities, access to and availability of transportation, processing, fractionation and refining 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 and derivative contracts and the purchasers of Pioneer's oil, NGL and gas production, uncertainties about estimates of reserves and resource potential 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, the risks associated with the ownership and operation of an industrial sand mining business and acts of war or terrorism. These and other risks are described in Pioneer's 10-K and 10-Q Reports 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. Pioneer undertakes no duty to publicly update these statements except as required by law. Please see the supplemental information slides included in this presentation for other important information. |
3 Financial and Operating Highlights Q4 2012 adjusted income of $107 MM, or $0.83 per adjusted share Q4 2012 production: 165 MBOEPD (including Barnett Shale production) Q4 2012 production: 156 MBOEPD excluding Barnett Shale production , mid-point of Q4 guidance range (154 MBOEPD – 158 MBOEPD) FY 2012 production averaged 156 MBOEPD (including Barnett Shale production), up 29% vs. FY 2011 (+54% oil growth) Top end of full-year guidance range Strong growth primarily related to successful Spraberry vertical, horizontal Wolfcamp Shale, Eagle Ford Shale and Barnett Shale Combo drilling programs Delivered 264% drillbit reserve replacement (161 MMBOE) in 2012 at drillbit F&D cost of $17.72 per BOE 4 Initiating $1 B horizontal drilling appraisal program of Pioneer’s northern Wolfcamp/Spraberry acreage for 2013 and 2014 $0.4 B included in 2013 drilling budget of $2.75 billion; remainder expected to be spent in 2014 Forecasting annual production growth of 12% to 16% from 2012 to 2013 Targeting 13% to 18% compound annual production growth for 2013 to 2015 1) Adjusted income and the adjusted per share amount are non-GAAP financial measures. See reconciliation in supplemental information slides 2) Barnett Shale properties were moved to discontinued operations in Q3 in conjunction with the divestment announcement; however, they were reclassified to continuing operations in Q4 after electing to retain these properties 3) Reflects South Africa as discontinued operations 4) Excludes price revisions 1 1 2 2 3 |
4 Drilling Highlights First PXD horizontal Wolfcamp Shale well (B interval) in Midland County highly successful; demonstrates prospectivity of Pioneer’s northern Wolfcamp/Spraberry acreage position (>600,000 gross acres) Announced $1.74 B horizontal Wolfcamp Shale joint interest transaction with Sinochem Horizontal Wolfcamp Shale results continuing to improve in joint interest area — Includes 1.6 BBOE from southern horizontal Wolfcamp Shale joint interest area and 3.0 BBOE from horizontal drilling in northern Wolfcamp/Spraberry acreage — Drilled first ~10,000-foot lateral horizontal Wolfcamp Shale well (Upper B interval) in Reagan County o 24-hour IP rate of 1,203 BOEPD; peak 20-day average rate of 1,022 BOEPD; oil content ~80% — Drilled first horizontal Wolfcamp Shale Lower B interval well and successful horizontal Wolfcamp Shale A interval well in Reagan County; both currently above 575 MBOE type curve — Well performance from existing wells continuing to meet type curve expectations — Achieved targeted year-end 2012 horizontal Wolfcamp Shale production exit rate of ~5 MBOEPD Increasing companywide net resource potential from 5.7 BBOE to >8 BBOE — 24-hour IP rate of 1,693 BOEPD; peak 20-day average natural flow rate of 1,510 BOEPD; oil content ~75% — 25 miles north of highly successful Giddings horizontal Wolfcamp Shale wells — Equates to ~$21,000 per acre on ~10% of Pioneer’s total Wolfcamp/Spraberry acreage position |
– $425 MM southern Wolfcamp joint interest area 2 – $575 MM Eagle Ford Shale – $185 MM Barnett Shale Combo – $190 MM Alaska – $150 MM Other (includes land capital for existing assets) – $2.0 B operating cash flow – $0.6 B joint interest cash proceeds – $0.4 B capital markets NYMEX Oil Price ($/Bbl) 2013 capital program based on $85/Bbl oil and $3.25/MMBtu gas Sensitivity to Commodity Prices ($ MM) 5 2013E Capital Spending and Cash Flow 1 1) Capital spending excludes acquisitions, asset retirement obligations, capitalized interest and G&G G&A 2) Pioneer incurs 100% of capital costs from January 1 st through estimated closing date of June 1 st ; Pioneer will be reimbursed by Sinochem for 40% of this amount as an adjustment at closing (not credited to cost incurred); Sinochem pays 40% of capital costs and carries Pioneer for 75% of Pioneer’s 60% of capital costs post closing 1.00 2.00 3.00 4.00 5.00 6.00 60.00 70.00 80.00 90.00 100.00 110.00 120.00 2 $240 MM Other Capital Capital program funded from: Capital program of $3.0 B includes: Drilling Capital: $2.75 B – $1,225 MM northern Wolfcamp/Spraberry area • $400 MM for horizontal program • $625 MM for vertical program • $200 MM for infrastructure & automation – $25 MM vertical integration – $70 MM sand mine expansion – $145 MM buildings, field offices and other |
High end of 2013-2015 growth range assumes $100 oil / $3.75 gas; low end assumes $85 oil / $3.25 gas 6 Targeting 13% - 18% Compound Annual Production Growth for 2013 - 2015 MBOEPD 147 160 165 58% Liquids 60% Liquids 175 - 181 156 MBOEPD (+29% vs. 2011) 1) Assumes $85/Bbl oil price and $3.25/MMBtu gas price 2) Excludes production attributable to the 40% joint interest transaction with Sinochem in the southern Wolfcamp area assuming a June 1, 2013 closing 3) Assumes no ethane rejected into the gas stream due to low ethane prices 3 Q1 Q2 Q3 Q4 2013E 2014E 2015E Excludes annualized 4+ MBOEPD conveyed to Sinochem post June 1 st 2,3 2012 151 3 |
Horizontal Wolfcamp Shale Well Results Continue to Improve 7 650 MBOE Type Curve Giddings Wells Average (southern joint interest area; 2 wells, 5,300’ laterals) Days University 10-1 #4H (southern joint interest area) First ~10,000’ lateral 24-hr IP of 1,203 BOEPD Peak 20-day average rate of 1,022 BOEPD; ~80% oil DL Hutt C #1H (Midland County) First northern acreage horizontal, 7,380’ lateral 24-hr IP natural flow rate of 1,693 BOEPD Peak 20-day average natural flow rate of 1,510 BOEPD; ~75% oil Giddings horizontal Wolfcamp Shale B interval wells drilled late 2011/early 2012 tracking 650 MBOE type curve First northern acreage well in Midland County and first 10,000’ lateral well in Reagan County both substantially above 650 MBOE type curve 2,000 1,000 100 Artificial lift commenced 0 30 60 90 120 150 180 210 240 270 300 330 360 |
Horizontal Jo Mill Wells Outperforming 650 MBOE Type Curve 8 Days 2,000 1,000 100 650 MBOE Type Curve Initial 2 horizontal Jo Mill wells drilled in Q4 2012 (average production normalized to 5,000’ lateral) |
Wolfcamp B Interval Prospectivity Map 9 Tier 1 Tier 1 Tier 2 Tier 2 Pioneer Land Pioneer Land DL Hutt C #1H 24-hr IP: 1,693 BOEPD Peak 20-day natural flow rate: 1,510 BOEPD; ~75% oil 7,380’ lateral length First Martin County B well drilling 7,200’ lateral length Tier 1 is highest prospectivity acreage, as determined by several geologic properties, including: Original oil in place (OOIP) Kerogen content Thermal maturity Porosity Brittle mineral fraction (fracability, low clay content) Vast majority of Pioneer’s acreage position is in Tier 1 Reservoir pressure increases with depth to the north and west Numerous wells have proven Tier 2 acreage to be productive and economic 2 Giddings Wells Avg. 24-hr IP: 845 BOEPD Avg. peak 20-day natural flow rate: 702 BOEPD: >75% oil 5,300’ avg. lateral length Third-party well Peak IP: 892 BOEPD ~3,700’ lateral length Pioneer Wolfcamp B wells Pioneer Wolfcamp B wells Wolfcamp B depth contour Wolfcamp B depth contour |
10 12/31/12 Proved Reserves: 1.1 BBOE Additional Net Resource Potential: >8 BBOE 1) All drilling locations shown on a gross basis 2) SEC pricing of $94.84/Bbl for oil and $2.76/MMBtu for gas (NYMEX) 3) Primarily reflects Alaska, Raton and South Texas 4) Includes vertical well potential from Wolfcamp and deeper intervals 5) Assumes average EUR of 500 MBOE per well, >600,000 gross acres, 140-acre spacing, Wolfcamp A, B & D and Jo Mill intervals (excludes Spraberry Shale interval potential) and 20% royalty 6) Assumes average EUR of 575 MBOE per well, 5,600 locations, 207,000 net acres , 140-acre spacing, laterals in all intervals (A, B, C & D), 25% royalty and Pioneer’s 60% share (reduced by ~1 BBOE associated with joint interest transaction) Permian >7 BBOE Significant Proved Reserves and Resource Potential 1 2 Proved Reserves + Estimated Net Resource Potential of >9 BBOE and >40,000 Drilling Locations |
11 Southern Wolfcamp Joint Interest Area Drilling Program Currently running 7 rigs; expect to increase to 10 rigs in 2014 and 13 rigs in 2015 Equates to 86 wells in 2013, 120 wells in 2014 and 165 wells in 2015 2013 drilling program continues to focus on delineating acreage Testing multiple Wolfcamp intervals (A, Upper B, Lower B and D) Targeting $7.5 MM - $8.0 MM gross development well cost for 7,800’ lateral o Testing laterals as long as 10,000’; ~$1.5 MM additional cost Expect 50% pad drilling Optimizing completion techniques o Testing slickwater fracs; potential savings of ~$1.0 MM/well Expect gross science costs of ~$20 MM Drilling program for 2014 and beyond primarily focused on development drilling and accelerating production growth Expect 75% pad drilling Expect to evaluate downspacing opportunities Noteworthy 24-hr IP rates in University Area 10-14 #6H – 712 BOEPD; First Lower B well 10-1#4H – 1,203 BOEPD; First 10,000’ lateral well 10-13#6H – 442 BOEPD; Successful A well Joint Interest Area (Wolfcamp and deeper intervals) |
Pioneer’s Highly Prospective Northern Wolfcamp/Spraberry Acreage 12 1 rig currently focused on delineating northern acreage (>600,000 gross acres) Drilled first two horizontal Wolfcamp Shale wells in Midland County ~25 miles north of highly successful Giddings horizontal Wolfcamp Shale wells First well completed in B interval (DL Hutt C #1H) Second well to be completed shortly in the A interval Rig now drilling first of two Wolfcamp B interval wells in Martin County Pioneer’s extensive Midland Basin geologic analysis, based upon data from thousands of wells, has identified multiple prospective horizontal targets with substantial oil in place throughout Pioneer’s northern acreage 2013 northern Wolfcamp/Spraberry drilling program accelerates appraisal and delineation of these targets (Wolfcamp Shales, Jo Mill and Spraberry Shales) with 4 rigs Currently drilling first of two wells in Martin County Pioneer’s northern Wolfcamp/Spraberry Acreage First two Midland County wells First two Giddings wells Joint Interest Area (Wolfcamp and deeper intervals) |
13 Northern Wolfcamp/Spraberry Acreage – 2013 Drilling Plan Wolfcamp A Wolfcamp B Wolfcamp D Jo Mill M. Spraberry Shale L. Spraberry Shale 15 to 20 wells 15 to 20 wells 2013 northern Wolfcamp/Spraberry acreage horizontal drilling program Running 1 rig currently; ramping to 4 rigs in Q2 Plan to drill a total of 30 to 40 wells targeting 6 different intervals Targeting $7.5 MM - $8.5 MM well cost for 7,000’ laterals depending on depth Excludes science and facilities capital of ~$80 MM U. Spraberry M. Spraberry Shale L. Spraberry Jo Mill L. Spraberry Shale Dean Wolfcamp A Wolfcamp Lower B Wolfcamp C1 Wolfcamp C2 Wolfcamp D Strawn Wolfcamp Upper B Miss/Atoka |
14 Northern Wolfcamp/Spraberry Acreage – Initiating $1 B Appraisal Program 2013 drilling program expected to cost ~$400 MM Program expected to: Appraise prospective acreage and confirm additional resource potential across 6 stacked intervals on >600,000 gross acres; totals >3 MM gross acres o Resource potential in Wolfcamp A, B and D intervals and Jo Mill interval across northern Wolfcamp/Spraberry acreage estimated to be 3 BBOE Deliver year-end 2013 horizontal production exit rate of 5 MBOEPD to 7 MBOEPD Improve capital efficiency compared to vertical drilling Expect to ramp up to 6 - 8 rigs during 2014 at a cost of ~$600 MM Continue appraisal program and commence development drilling May also test horizontal drilling in deeper intervals below the Wolfcamp Shale Spending $1 B over 2 years to confirm ~3 BBOE of resource potential and add substantial NAV 2013 Appraisal Areas Planned 2013 appraisal areas; 6 intervals |
Spraberry Vertical Drilling Program 15 Limestone Pay Sandstone Pay Non-Organic Shale Non-Pay Organic Rich Shale Pay Commingled Wells Placed on Production in 2012 2012 Average 24-hour IP (BOEPD) Potential Incremental EUR (MBOE) Prospective PXD Acreage Strawn 208 145 30 up from ~70% to ~85% Atoka 134 180 50 – 70 40% - 50% Mississippian 55 140 15 – 40 ~20% 1) Compares to average vertical well completed through the Lower Wolfcamp with an average EUR of 140 MBOE and an average 24-hour IP of 90 BOEPD Deeper drilling accounted for 65% of 2012 vertical drilling program; expected to increase to 90% in 2013 Vertical rig count reduced during 2012 from 40 rigs in Q1 to 20 rigs at year-end as horizontal activity increased – Drilled 132 vertical wells in Q4 and 631 wells in 2012 – Built frac bank by 57 vertical wells over 2H 2012 2013 drilling program runs 15 vertical rigs and drills ~300 wells – Majority of rigs required to meet continuous drilling obligations – 15 rigs to 20 rigs required to keep vertical production flat – Expect to draw down frac bank by 60 - 70 vertical wells during 2013 Dean Deeper drilling provides potential to add up to 100 MBOE to vertical Wolfcamp well 1 1 |
Continuing to Successfully Grow Wolfcamp/Spraberry Production 16 Wolfcamp/Spraberry Net Production 1 (MBOEPD) 1) Includes production from Strawn, Atoka and Mississippian intervals in Spraberry vertical wells and horizontal Wolfcamp Shale and Jo Mill wells 45 62 2012 64 69 69 75-80 66 MBOEPD Q4 production flat compared to Q3 due to: ~1,700 BOEPD negative impact related to reduced ethane recoveries resulting from Spraberry gas processing facilities operating above capacity due to greater-than-anticipated industry production growth Vertical wells awaiting completion increased by 57 wells during 2H Reduced ethane recoveries expected to continue into Q2 2013 until new Driver plant comes online in April providing additional capacity of 200 MMCFPD Negative impact to Pioneer’s Q1 production expected to be 2,000 BOEPD to 3,000 BOEPD Vertical rig count decreasing from average of 32 rigs in 2012 to 15 rigs in 2013 Horizontal rig count increasing from average of 3 rigs in 2012 to 11 rigs in 2013 Expect horizontal production to increase from an average of 2 MBOEPD in 2012 to 11 MBOEPD to 14 MBOEPD in 2013 2 2,3 Top end of original FY guidance range (63 MBOEPD – 67 MBOEPD) Horizontal production exit rate: ~5 MBOEPD 2) Production reduced after June 1 st to reflect the divested volumes associated with the southern Wolfcamp joint interest transaction 3) Assumes no ethane rejected into the gas stream due to low ethane prices |
Eagle Ford Shale Operational Update 17 Drilled 30 wells in Q4 2012; 37 wells placed on production 2013 drilling program Expanding use of white sand proppant to deeper areas to further define its performance limits (>50% of 2013 program) ~97 wells stimulated using white sand in 2011 and 2012; early well performance similar to direct offset ceramic-stimulated wells Reduces frac cost by ~$700 M Expect to increase lateral length from 5,700’ in 2012 to 6,200’ in 2013; increases cost by $500 M per well Well cost: $7 MM to $8 MM 11 CGPs on line; adding 12 by end of 2013 th Expect to drill ~130 wells Drilling essentially all liquids-rich wells ~80% pad drilling, up from 45% in 2012; saves $600 M to $700 M per well and allows 130 wells to be drilled with 10 rigs vs. 12 rigs last year |
Eagle Ford Shale Continues to Set New Production Records 18 Eagle Ford Shale Net Production (MBOEPD) 12 1) Reflects Pioneer’s ~35% share of total gross production 2) Assumes no ethane rejected into the gas stream due to low ethane prices 28 MBOEPD 2012 Top end of original FY guidance range (25 MBOEPD – 29 MBOEPD) 2 2011 Q1 Q2 Q3 Q4 2013E 1 38 - 42 35 29 24 23 |
Continuing to Grow Barnett Shale Combo Production 19 Barnett Shale Net Production (MBOEPD) 4 6 2012 7 9 - 12 7 9 7 MBOEPD Drilled 8 wells in Q4; 8 wells placed on production Expect to increase rig count from 1 rig to 2 rigs in Q2 2013 to hold high-graded acreage ~20% of 82,000 net acreage position currently HBP Drilling data and petrophysical and seismic analysis have identified highest-return areas across Pioneer’s acreage (reflects ~45,000 net acres of remaining ~65,000 non-HBP net acres) Increase in drilling efficiencies requires fewer rigs to hold acreage 2-rig drilling program required to hold the higher- return acreage over next 3 years Well cost for 5,000’ lateral: ~$3 MM Gross EUR: ~400 MBOE (16% oil, 42% NGLs, 42% gas) 1) Assumes no ethane rejected into the gas stream due to low ethane prices 1 |
20 Alaska Q4 net production: ~4 MBOPD 1-rig development program continues from the Oooguruk island drill site targeting Nuiqsut and Torok intervals Following first successful mechanically diverted frac on a Nuiqsut well in 2012, planning similar fracs for 1 Torok and 3 Nuiqsut wells during Q1 2 onshore Torok appraisal well being drilled Will be completed with mechanically diverted frac Initial onshore Torok well added 50 MMBO resource potential in 2012; currently being flow tested and is producing at a facility-limited rate of 2,800 BOPD gross Progressing onshore development FEED study for Torok production PXD Acreage Island Development Area Island drill site (Oooguruk) Torok Area 1 well to be frac’d from island drill site and 1 well to be frac’d from onshore drill site Nuiqsut Area 3 wells to be frac’d from island drill site Nuiqsut Wells Torok Wells nd Second onshore Torok appraisal well Torok onshore drill site |
Net income attributable to common stockholders 29 0.22 Unrealized mark-to-market (MTM) derivative gains ($22 MM before tax) (14) (0.11) Adjusted income excluding unrealized MTM derivative gains 15 0.11 Unusual items included in adjusted income: Impairment of Barnett Shale assets previously held for sale ($160 MM before tax) 101 0.78 Alaska Petroleum Production Tax credit income ($14 MM before tax) (9) (0.06) Adjusted income excluding unrealized MTM derivative gains and unusual items 107 0.83 21 Q4 2012 Earnings Summary $ Per Share $ Millions (After Tax) Guidance Q4 2012 Results Excluding Unrealized MTM Derivative Gains, Unusual Items and Barnett Shale Activity Q4 2012 Results from Continuing Operations Daily Production (MBOEPD) 154 – 158 156 165 Production Costs Including Taxes ($/BOE) $14.50 - $16.50 $ 14.48 $ 14.62 Exploration & Abandonment ($ MM) $25 - $35 $ 16 $ 89 DD&A ($/BOE) $13.50 - $15.50 $ 14.63 $ 14.54 G&A 4 ($ MM) $60 - $65 $ 68 $ 68 Interest Expense ($ MM) $53 - $58 $ 54 $ 54 Other Expense ($ MM) $25 - $35 $ 27 $ 27 Accretion of Discount on ARO ($ MM) $2 - $4 $ 2 $ 3 Noncontrolling Interest ($ MM) $8 - $11 $ 8 5 $ 11 Current Income Taxes /(Benefits) ($ MM) $2 - $7 - - Effective Tax Rate 6 (%) 35% - 40% 34% 24% Q4 2012 Guidance vs. Results 1) Non-GAAP financial measure. See reconciliation in supplemental information slides 2) 3) Exploration and abandonments in continuing operations included $72 MM of unproved impairments on Barnett Shale assets (included in unusual items above) 4) Includes additional performance-related compensation 5) Excludes unrealized MTM derivative gains attributable to noncontrolling interest of $ 3 MM in Q4 2012 6) Excludes income attributable to noncontrolling interest of $ 11 MM in Q4 2012 1 1 2 3 Q4 production was negatively impacted by a total of ~1,700 BOEPD due to reduced ethane recoveries at Spraberry gas processing facilities |
22 Price Realizations 1 Oil ($/BBL) NGL ($/BBL) Gas ($/MCF) Derivative impact included in price 1.79 (0.15) (0.42) - - - - - - - - - - - - Derivative impact not included in price Price 92.74 99.73 87.94 89.77 87.78 44.20 42.57 34.48 32.49 31.48 4.81 4.49 4.43 4.48 4.48 VPP and derivative impact 1.23 0.58 1.07 1.68 3.89 (1.50) 0.76 1.86 1.53 0.79 1.44 1.98 2.43 1.86 1.28 VPPs and Derivatives Realized Prices (excludes VPPs and derivatives) Price including VPPs and all derivatives VPPs 2.45 1.99 1.87 1.79 1.71 - - - - - - - - - - 1) All periods presented have been restated to exclude discontinued operations 2) Represents cash settlements recorded in net derivative gains or losses excluding liquidated derivatives 91.51 45.70 3.37 99.15 41.81 2.51 86.87 32.62 2.00 88.09 83.89 30.96 30.69 2.62 3.20 Q4 11 Q1 12 Q2 12 Q3 12 Q4 12 Q4 11 Q1 12 Q2 12 Q3 12 Q4 12 Q4 11 Q1 12 Q2 12 Q3 12 Q4 12 (3.01) (1.26) (0.38) (0.11) 2.18 (1.50) 0.76 1.86 1.53 0.79 1.44 1.98 2.43 1.86 1.28 2 |
23 Production Costs (per BOE) 1 VPP-Adjusted Production Cost 1) 2) See supplemental information slides $13.16 $12.99 $13.88 $15.27 $14.32 Q4 production cost decrease vs. Q3 primarily due to the following LOE items: – Lower salt water disposal costs – Lower electricity costs – Lower repair and maintenance costs All periods presented have been restated to exclude discontinued operations and intercompany eliminations Production & Ad Valorem Taxes Workovers LOE Third Party Transportation Natural Gas Processing Q4 ’11 $13.52 Q1 ’12 $0.30 $13.30 $0.24 Q2 ’12 $14.21 $0.64 Q3 ’12 $0.59 Q4 ’12 $0.42 $15.61 $14.62 $0.68 $3.18 $1.36 $8.00 $7.70 $8.08 $9.61 $8.68 $1.24 $1.28 $1.28 $1.40 $3.43 $3.25 $3.38 $3.14 $0.69 $0.96 $0.75 $0.98 |
24 Q1 2013 Guidance Daily Production (MBOEPD) 165 – 170 Production Costs ($/BOE) $14.00 – $16.00 Exploration & Abandonment ($ MM) $25 – $35 Drilling and Acreage $15 Personnel and Seismic $20 DD&A ($/BOE) $13.50 – $15.50 G&A ($ MM) $60 – $65 Interest Expense ($ MM) $53 – $58 Other Expense ($ MM) $25 – $35 Accretion of Discount on ARO ($ MM) $2 – $4 Noncontrolling Interest (principally PSE) ($ MM) $8 – $11 Current Income Taxes ($ MM) $2 – $7 Effective Tax Rate (%) 35% – 40% Guidance 1 1) Excludes MTM derivative changes due to increases or decreases in future commodity prices |
25 Supplemental Information Supplemental Information Slides Slide # 2012 Reserve Additions 26 2012 Drilling Capital 27 Liquidity Position 28 Historic Production 29 - 30 Oil and Gas Revenue 31 Derivative Position 32 - 34 Oil, NGL and Gas Differentials 35 - 37 General & Administrative Costs 38 Interest Costs 39 Exploration and Abandonments 40 Income Taxes 41 Supplemental Non-GAAP Financial Measures 42 Supplemental Earnings Per Share Information 43 Supplemental Non-GAAP Financial Measures 44 - 45 VPP - Adjusted Production Costs 46 Reserves Audit, F&D Costs and Reserve Replacement 47 Certain Reserve Information 48 |
Added 161 MMBOE from the drillbit, or 264% of full-year production, at a drillbit F&D cost of $17.72 per BOE Reflects significant drilling campaigns in horizontal Wolfcamp Shale, Spraberry vertical, Eagle Ford Shale and Barnett Shale Combo plays All-in reserve replacement of 87 MMBOE, or 144% of full- year production at an all-in F&D cost of $34.46 per BOE, including: Negative pricing revisions of 82 MMBOE due to significant decline in gas prices Negative technical revisions of 27 MMBOE; performance improvements of 53 MMBOE offset by 80 MMBOE of vertical Spraberry PUDs moved to the probable category as the Company shifts to more horizontal drilling in the Spraberry field based on successful horizontal Wolfcamp Shale drilling results Reserve mix 100% U.S. 45% oil / 21% NGLs / 34% gas 58% PD / 42% PUD Proved Reserves / Production: ~18 years PD Reserves / Production: ~10 years 26 Strong 2012 Reserve Additions 1 Year-end ’12 Proved Reserves (MMBOE) 627 119 116 101 55 44 23 1 1,086 1) Reflects 2012 SEC pricing (12-month average) of $94.84/Bbl for oil and $2.76/MMBtu for gas (NYMEX) as compared to 2011 SEC pricing of $96.13/Bbl for oil and $4.12/MMBtu for gas (NYMEX) Spraberry Raton Eagle Ford Mid-Continent Barnett Shale Alaska South Texas Other Total |
27 2012 Drilling Capital 1 1) Excludes acquisitions, asset retirement obligations, capitalized interest and G&G G&A $ Millions $741 $678 $639 $670 $2,728 Q1 2012 Q2 2012 Q3 2012 Q4 2012 FY 2012 |
28 Liquidity Position (12/31/12) 1 Net debt (net of cash balance of $229 MM): $3.4 B Unsecured credit facility availability: $1.0 B Net debt-to-book capitalization: 37% 1) Excludes $126 MM of borrowings under PSE’s $300 MM credit facility that matures in March 2017 2) Excludes net discounts and deferred hedge losses of ~$49 MM 3) Convertible senior notes due 2038; based on trading value, interest rate reduced to 2.375% from 2.875% effective January 15, 2013; holders of $241 MM in principal amount exercised their right to convert in Q1 4) Excludes ~$2 MM of outstanding letters of credit on credit facility; credit facility balance as of January 31, 2013 was $750 MM Maturities and Balances 2 Unsecured credit facility matures in 2017 Investment grade rated Expect to call convertible senior notes due 2038 for redemption during 2013 2012 2016 $600 MM 3.95% 2017 $455 MM 5.875% 2022 $450 MM 6.875% $474 MM 4 of $1.5 B unsecured credit facility 2018 $485 MM 6.65% 2013 $480 MM 3 2.375% $450 MM 7.50% 2020 $250 MM 7.20% 2028 |
29 Production (MBOEPD) 1 Q4 ’11 Q1 ’12 Q2 ’12 Q3 ’12 Q4 ’12 Spraberry 53 62 64 2 69 3 69 4 Eagle Ford Shale 20 23 24 29 35 Raton 26 26 25 25 24 South Texas 7 7 6 6 6 Mid-Continent 19 18 18 18 17 Barnett 6 6 7 7 9 Alaska 4 4 5 5 4 Other 2 1 2 1 1 Total 137 147 151 160 165 1) 2) Q2 ‘12 production negatively impacted by ~4,800 BOEPD due to unplanned third party fractionation capacity shortfalls at Mont Belvieu 3) continuing ethane rejection and 3 rd party fractionation capacity constraints at Mont Belvieu 4) All periods presented have been restated to exclude discontinued operations Q4 production was negatively impacted by a total of ~1,700 BOEPD due to reduced ethane recoveries at Spraberry gas processing facilities Q3 ’12 production benefited by ~1,800 BPD from partial NGL inventory drawdown at Mont Belvieu, but offset by a production loss of ~4,000 BOEPD due to |
PXD Production By Commodity By Area 1 30 1) All periods presented have been restated to exclude discontinued operations |
31 Oil and Gas Revenue 1 $ Millions VPP Deferred Revenue $665 $719 $642 $716 $735 $654 $710 $632 $706 $725 $11 $9 $10 $10 $10 Q4 '11 Q1 '12 Q2 '12 Q3 '12 Q4 '12 1) All periods presented have been restated to exclude discontinued operations |
32 Swaps – WTI (BPD) 3,000 3,000 3,000 3,000 - - NYMEX WTI Price ($/BBL) $ 81.02 $ 81.02 $ 81.02 $ 81.02 - - Three Way Collars – (BPD) 1 66,750 68,750 72,750 75,750 69,000 26,000 NYMEX Call Price ($/BBL) $ 119.31 $ 119.42 $ 119.74 $ 120.47 $ 114.05 $ 104.45 NYMEX Put Price ($/BBL) $ 92.30 $ 92.38 $ 92.53 $ 91.90 $ 93.70 $ 95.00 NYMEX Short Put Price ($/BBL) $ 74.01 $ 74.19 $ 74.51 $ 74.39 $ 77.61 $ 80.00 % Total Oil Production ~95% ~95% ~95% ~95% ~75% ~25% Three Way Collars – (BPD) 1 1,064 1,064 1,064 1,064 1,000 - NYMEX Call Price ($/BBL) $ 105.28 $ 105.28 $ 105.28 $ 105.28 $ 109.50 - NYMEX Put Price ($/BBL) $ 89.30 $ 89.30 $ 89.30 $ 89.30 $ 95.00 - NYMEX Short Put Price ($/BBL) $ 75.20 $ 75.20 $ 75.20 $ 75.20 $ 80.00 - % Total NGL Production <5% <5% <5% <5% <5% - % Total Liquids ~65% ~65% ~65% ~65% ~55% ~15% Midland/Cushing Swaps (BPD) 3,278 5,000 - - - - Price Differential ($/BBL) $ (5.75) $ (5.75) - - - - Cushing/LLS Swaps (BPD) - - - 1,000 - - Price Differential ($/BBL) - - - $(7.60) - - Spraberry Fixed Differential 2 24,000 26,000 28,000 30,000 33,000 35,000 Price Differential ($/BBL) $ (1.75) $ (1.75) $ (1.75) $ (1.75) $ (1.75) $ (1.75) Oil Basis Protection Q1 2013 Q2 2013 Q3 2013 Q4 2013 2014 2015 Natural Gas Liquids Q1 2013 Q2 2013 Q3 2013 Q4 2013 2014 2015 Q1 2013 Q2 2013 Q3 2013 Q4 2013 2014 2015 Oil PXD Open Commodity Derivative Positions as of 2/8/2013 (includes PSE) 1) When NYMEX price is above call price, PXD receives call price. When NYMEX price is between put price and call price, PXD receives NYMEX price. When NYMEX price is between the put price and the short put price, PXD receives put price. When NYMEX price is below the short put price, PXD receives NYMEX price plus the difference between the short put price and put price 2) Market transaction representing Midland/Cushing differential; not a derivative |
33 Swaps - (MMBTUPD) 162,500 162,500 162,500 162,500 105,000 - NYMEX Price ($/MMBTU) 1 $ 5.13 $ 5.13 $ 5.13 $ 5.13 $ 4.03 - Collars - (MMBTUPD) 150,000 150,000 150,000 150,000 - - NYMEX Call Price ($/MMBTU) 1 $ 6.25 $ 6.25 $ 6.25 $ 6.25 - - NYMEX Put Price ($/MMBTU) 1 $ 5.00 $ 5.00 $ 5.00 $ 5.00 - - Three Way Collars – (MMBTUPD) 1,2 - - - - 25,000 225,000 NYMEX Call Price ($/MMBTU) - - - - $4.70 $ 5.09 NYMEX Put Price ($/MMBTU) - - - - $4.00 $ 4.00 NYMEX Short Put Price ($/MMBTU) - - - - $3.00 $ 3.00 % Total Gas Production ~80% ~80% ~80% ~80% ~30% ~55% Spraberry (MMBTUPD) 52,500 52,500 52,500 52,500 - - Price Differential ($/MMBTU) $ (0.23) $ (0.23) $ (0.23) $ (0.23) - - Mid-Continent (MMBTUPD) 50,000 50,000 50,000 50,000 10,000 - Price Differential ($/MMBTU) $ (0.30) $ (0.30) $ (0.30) $ (0.30) $ (0.19) - Gulf Coast (MMBTUPD) 60,000 60,000 60,000 60,000 - - Price Differential ($/MMBTU) $ (0.14) $ (0.14) $ (0.14) $ (0.14) - - Gas Basis Swaps Q1 2013 Q2 2013 Q3 2013 Q4 2013 2014 2015 Q1 2013 Q2 2013 Q3 2013 Q4 2013 2014 2015 Gas PXD Open Commodity Derivative Positions as of 2/8/2013 (includes PSE) 1) 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, PXD receives call price. When NYMEX price is between put price and call price, PXD receives NYMEX price. When NYMEX price is between the put price and the short put price, PXD receives put price. When NYMEX price is below the short put price, PXD receives NYMEX price plus the difference between short put price and put price |
34 1) When NYMEX price is above call price, PSE receives call price. When NYMEX price is between put price and call price, PSE receives NYMEX price. When NYMEX price is between the put price and the short put price, 2) Approximate NYMEX price based on differentials to index prices at the date the derivative was entered into Oil Q1 2013 Q2 2013 Q3 2013 Q4 2013 2014 2015 Swaps (BPD) 3,000 3,000 3,000 3,000 - - NYMEX Price ($/BBL) $81.02 $81.02 $81.02 $81.02 - - Three-Way Collars (BPD) 1,750 1,750 1,750 1,750 5,000 - NYMEX Call Price ($/BBL) $116.00 $116.00 $116.00 $116.00 $105.74 - NYMEX Put Price ($/BBL) $88.14 $88.14 $88.14 $88.14 $100.00 - NYMEX Short Put Price ($/BBL) $73.14 $73.14 $73.14 $73.14 $80.00 - % Oil Production ~85% ~85% ~85% ~85% ~85% - Gas Swaps (MMBTUPD) 2,500 2,500 2,500 2,500 5,000 - NYMEX Price ($/MMBTU) $6.89 $6.89 $6.89 $6.89 $4.00 - Three-Way Collars (MMBTUPD) - - - - - 5,000 NYMEX Call Price ($/MMBTU) - - - - - $5.00 NYMEX Put Price ($/MMBTU) - - - - - $4.00 NYMEX Short Put Price ($/MMBTU) - - - - - $3.00 % Gas Production ~35% ~35% ~35% ~35% ~70% ~65% % Total Production ~65% ~65% ~65% ~65% ~70% ~10% Gas Basis Swaps Q1 2013 Q2 2013 Q3 2013 Q4 2013 2014 2015 Spraberry (MMBTUPD) 2,500 2,500 2,500 2,500 - - Price Differential ($/MMBTU) (0.31) (0.31) (0.31) (0.31) - - PSE Derivative Position as of 2/8/2013 1, 2 2 1 PSE receives put price. When NYMEX price is below the short put price, PSE receives NYMEX price plus the difference between the short put price and put price |
Q4 ’11 Q1 ’12 Q2 ’12 Q3 ’12 Q4 ’12 NYMEX calendar month average $ 94.06 $ 102.93 $ 93.49 $ 92.22 $ 88.18 NYMEX differential (2.55) (3.78) (6.62) (4.13) (4.29) Realized prices excluding VPPs and derivatives 91.51 99.15 86.87 88.09 83.89 Impact of VPPs and derivatives included in price VPPs 2.45 1.99 1.87 1.79 1.71 Derivatives included in price 1.79 (0.15) (0.42) - - Reported prices including VPPs and derivatives included in price 95.75 100.99 88.32 89.88 85.60 Derivatives not included in price (3.01) (1.26) (0.38) (0.11) 2.18 Price including VPPs and all derivatives $ 92.74 $ 99.73 $ 87.94 $ 89.77 $ 87.78 35 Oil Differentials (per BBL) 2 1 1) All periods presented have been restated to exclude discontinued operations 2) Represents cash settlements recorded in net derivative gains or losses excluding liquidated derivatives |
36 NGL Differentials (per BBL) Q4 ’11 Q1 ’12 Q2 ’12 Q3 ’12 Q4 ’12 NYMEX oil calendar month average $ 94.06 $ 102.93 $ 93.49 $ 92.22 $ 88.18 NYMEX differential (48.36) (61.12) (60.87) (61.26) (57.49) Realized prices excluding derivatives 45.70 41.81 32.62 30.96 30.69 Impact of derivatives included in price - - - Reported prices including derivatives included in price 45.70 41.81 32.62 30.96 30.69 Derivatives not included in price (1.50) 0.76 1.86 1.53 0.79 Price including all derivatives $ 44.20 $ 42.57 $ 34.48 $ 32.49 $ 31.48 Realized NGL prices excluding derivatives as a percentage of NYMEX oil calendar month average 49% 41% 35% 34% 35% 1 2 1) All periods presented have been restated to exclude discontinued operations 2) Represents cash settlements recorded in net derivative gains or losses excluding liquidated derivatives |
37 Gas Differentials (per MCF) 1 Q4 ’11 Q1 ’12 Q2 ’12 Q3 ’12 Q4 ’12 NYMEX bid week average $ 3.55 $ 2.72 $ 2.21 $ 2.80 $ 3.41 NYMEX differential (0.18) (0.21) (0.21) (0.18) (0.21) Realized prices excluding derivatives 3.37 2.51 2.00 2.62 3.20 Impact of derivatives included in price - - - - - Reported prices including derivatives included in price 3.37 2.51 2.00 2.62 3.20 Derivatives not included in price 2 1.44 1.98 2.43 1.86 1.28 Price including all derivatives $ 4.81 $ 4.49 $ 4.43 $ 4.48 $ 4.48 1) All periods presented have been restated to exclude discontinued operations 2) Represents cash settlements recorded in net derivative gains or losses excluding liquidated derivatives |
38 General & Administrative Costs 1 $ Millions Noncash Q4 2011 1) All periods presented have been restated to exclude discontinued operations Q1 2012 $55 Q2 2012 $63 Q3 2012 $55 Q4 2012 $63 $68 Includes performance-based compensation awards for 2012 |
39 Interest Costs 1 $ Millions Q4 2011 1) All periods presented have been restated to exclude discontinued operations $46 Q1 2012 Q2 2012 $47 $49 Q3 2012 Q4 2012 $54 Noncash $54 |
40 Exploration & Abandonments Drilling & Acreage Barnett Shale $ 72 Acreage & Other 1 73 Geological & Geophysical Seismic 2 Personnel & Other 14 16 4 th Quarter 2012 Total $ 89 $ Millions |
41 Quarter Ended December 31, 2012 ($ Millions) Current tax benefit Deferred tax provision Income Taxes Attributable to Continuing Operations $ - (9) $ (9) |
Net Income $ 40 Depletion, depreciation and amortization 220 Exploration and abandonments 89 Impairment 88 Accretion of discount on asset retirement obligations 3 Interest expense 54 Income tax provision 9 Gain on disposition of assets, net (1) Derivative related activity (24) Amortization of stock-based compensation 16 Amortization of deferred revenue (11) Other noncash items (19) EBITDAX 464 Cash interest expense (45) Discretionary cash flow 419 Cash exploration expense (16) Changes in operating assets and liabilities 77 Net cash provided by operating activities $ 480 42 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. Q4 ’12 ($ Millions) |
Weighted average basic and diluted common shares outstanding Basic 123,240 Dilutive common stock options 143 Contingently issuable performance unit shares 196 Convertible senior notes dilution 3,366 Diluted 126,945 43 Supplemental Earnings Per Share Information Q4 2012 Q4 2012 Net income attributable to common stockholders $ 28,834 Participating share- and unit-based basic earnings (516) Basic net income attributable to common stockholders Diluted effect of participating securities 24 Diluted net income attributable to common stockholders $ 28,342 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. 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 share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. 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 loss from continuing operations 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 net income attributable to common stockholders and to diluted net income attributable to common stockholders for the three months ended December 31, 2012 (in thousands): 28,318 |
44 Supplemental Non-GAAP Financial Measures $ Per Share $ Millions (After Tax) Net income attributable to common stockholders 29 0.22 Unrealized MTM derivative gains ($22 MM before tax) (14) (0.11) Adjusted income excluding unrealized MTM derivative gains 15 0.11 Unusual items included in adjusted income: Impairment of Barnett Shale assets previously held for sale ($160 MM before tax) 101 0.78 Alaska Petroleum Production Tax credit income ($14 MM before tax) (9) (0.06) Adjusted income excluding unrealized MTM derivative gains and unusual items Adjusted income excluding unrealized MTM derivative gains and adjusted income excluding unrealized MTM derivative gains and unusual items, as presented in the Q4 2012 Earnings Summary slide, is presented and reconciled to Pioneer’s net income attributable to common stockholders and diluted common shares outstanding (determined in accordance with GAAP) because Pioneer believes that these non-GAAP financial measures reflect an additional way of viewing aspects of Pioneer’s business that, when viewed together with its financial results computed in accordance with GAAP, provides 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 these non-GAAP measures may enhance investors’ ability to assess Pioneer’s historical and future financial performance. These non-GAAP financial measures are not intended to be substitutes for the comparable GAAP measures and should be read only in conjunction with Pioneer’s consolidated financial statements prepared in accordance with GAAP. Unrealized MTM derivative gains and losses and unusual items 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 December 31, 2012, as determined in accordance with GAAP, to adjusted income excluding unrealized MTM derivative gains and adjusted income excluding unrealized MTM derivative gains and unusual items for that quarter. 0.83 107 |
Supplemental Non-GAAP Financial Measures Q4 2012 Results from Continuing Operations Adjustments to Exclude Barnett Shale Q4 2012 Operating Results (1) Adjustments to Exclude Unrealized MTM Derivative Gains and Unusual Items Q4 2012 Results Excl. Unrealized MTM Derivative Gains, Unusual Items and Barnett Shale Activity Daily Production (MBOEPD) 165 (9) 156 Production Costs ($/BOE) 14.62 (0.14) 14.48 Exploration & Abandonment ($ MM) 89 (73) 16 DD&A ($/BOE) 14.54 0.09 14.63 G&A ($ MM) 68 68 Interest Expense ($ MM) 54 54 Other Expense ($ MM) 27 27 Accretion of Discount on ARO ($ MM) 3 (1) 2 Noncontrolling Interest 11 (3) 8 Current Tax Provision (Benefit) - - Effective Tax Rate 2 (%) 24% (10%) 34% (1) The Company’s Barnett Shale properties were reclassified to discontinued operations during the third quarter of 2012 as a result of the Company’s decision to divest of these properties (2) The effective tax rates in the adjustment columns represent the effective tax rates attributable to the results or adjustments applicable to that column 45 Selected Q4 2012 results excluding Barnett Shale activity and excluding unrealized MTM derivative gains and unusual items, as presented in the Q4 2012 Earnings Summary Slide, are presented and reconciled to the comparable GAAP results in the table below because Pioneer believes that these non-GAAP financial measures reflect 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 these non-GAAP measures may enhance investors’ ability to assess Pioneer’s historical and future financial performance. These non-GAAP financial measures are not intended to be substitutes for the comparable GAAP measure and should be read only in conjunction with Pioneer’s consolidated financial statements prepared in accordance with GAAP. |
46 VPP – Adjusted Production Costs Pioneer presents VPP-Adjusted Production Costs (per BOE) to assist investors in considering the Company’s costs in relation to the total BOEs (reported sales volumes plus VPP delivered volumes) in connection with which those costs were incurred. VPP-Production Costs (per BOE) are calculated as follows: Q4 ’11 Q1 ’12 Q2 ’12 Q3 ’12 Q4 ‘12 Production costs as reported (thousands) $ 170,000 $ 177,579 $ 194,574 $ 229,467 $ 221,781 Production (MBOE): As reported 12,576 13,352 13,696 14,710 15,163 VPP deliveries 345 319 319 322 322 VPP-adjusted production 12,921 13,671 14,015 15,032 15,485 Production costs per BOE: As reported $ 13.52 $ 13.30 $ 14.21 $ 15.61 $14.62 VPP-adjusted $ 13.16 $ 12.99 $ 13.88 $ 15.27 $14.32 1) All periods presented have been restated to exclude discontinued operations and intercompany eliminations 1 |
47 An audit of proved reserves follows the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers ("SPE"). A reserve audit as defined by the SPE is not the same as a financial audit. Please see the Company's Annual Report on Form 10- K for a general description of the concepts included in the SPE's definition of a reserve audit. "Finding and development cost per BOE," or “all-in F&D cost per BOE,” means total costs incurred divided by the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates, purchases of minerals-in-place, discoveries and extensions and improved recovery. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. "Drillbit finding and development cost per BOE," or “drillbit F&D cost per BOE,” means the summation of exploration and development costs incurred divided by the summation of annual proved reserves, on a BOE basis, attributable to technical revisions of previous estimates, discoveries and extensions and improved recovery. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. “Reserve replacement” is the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates, purchases of minerals-in-place, discoveries and extensions and improved recovery divided by annual production of oil, NGLs and gas, on a BOE basis. “Drillbit reserve replacement” is the summation of annual proved reserves, on a BOE basis, attributable to technical revisions of previous estimates, discoveries and extensions and improved recovery divided by annual production of oil, NGLs and gas, on a BOE basis. Reserves Audit, F&D Costs and Reserve Replacement |
48 Certain Reserve Information Cautionary Note to U.S. Investors --The U.S. Securities and Exchange Commission (the "SEC") prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. In this presentation, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource,” “resource potential,” “EUR”, “oil in place” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer. U.S. investors are urged to consider closely the disclosures in the Company’s periodic filings with the SEC. Such filings are available from the Company at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039, Attention Investor Relations, and the Company’s website at www.pxd.com. These filings also can be obtained from the SEC by calling 1-800-SEC- 0330. |