Core Oil Delaware Basin Pure-Play Second Quarter 2017 Earnings - - PowerPoint PPT Presentation

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Core Oil Delaware Basin Pure-Play Second Quarter 2017 Earnings - - PowerPoint PPT Presentation

Core Oil Delaware Basin Pure-Play Second Quarter 2017 Earnings Presentation August 7, 2017 Important Information Forward-Looking Statements The information in this presentation includes forward -looking statements within the meaning of


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SLIDE 1

Second Quarter 2017 Earnings Presentation

August 7, 2017

Core Oil Delaware Basin Pure-Play

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SLIDE 2

Important Information

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Forward-Looking Statements The information in this presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E

  • f the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this presentation, regarding our strategy, future
  • perations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When

used in this presentation, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in our filings with the Securities and Exchange Commission. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this presentation. Use of Non-GAAP Financial Measures This presentation includes the non-GAAP financial measure, Adjusted EBITDAX. Please refer to slide 15 for a reconciliation of Adjusted EBITDAX to net (loss) income, the most comparable GAAP measure. We believe Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to financing methods of capital structure. We exclude the items listed in slide 15 from net (loss) income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic cost of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to

  • ther similarly titled measures of other companies.
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SLIDE 3

Centennial – Q2 2017 highlights

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▪ Reported $20.8mm of GAAP net income(1) and $63.1mm of adjusted EBITDAX(2) ▪ Increased Q2 2017 average daily oil production volumes by 66% compared to Q1 2017; average daily oil equivalent volumes up 61% – Increased oil commodity mix to 59% in Q2 from 57% in Q1 ▪ Increased full-year 2017 oil and oil equivalents production guidance by 14% and 15%, respectively ▪ Reported 5 of the strongest recent industry Reeves County horizontal wells on a Bo/d / 1,000’ basis ▪ Lowered all full-year 2017 unit cost estimates – LOE, cash G&A, gathering, processing & transportation, DD&A and severance & ad valorem taxes ▪ Deferred addition of 7th rig previously planned for the second half of 2017 – Full-year capital and well count guidance remains unchanged

(1) Net income attributable to common shareholders (2) Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States. Please see slide 15 for a reconciliation to net income, our most directly comparable financial measure calculated and presented in accordance with GAAP.

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SLIDE 4

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Operational and financial outperformance

(1) Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States. Please see slide 15 for a reconciliation to net income, our most directly comparable financial measure calculated and presented in accordance with GAAP. (2) Net income attributable to common shareholders (3) Q1 2017 G&A / Boe metric includes ~$1.8mm in one-time / non-recurring charges

Oil production (Bo/d) Oil equivalent production (Boe/d) LOE ($/Boe) Cash G&A ($/Boe)3

10,489 17,435 Q1 2017 Q2 2017 18,469 29,664 Q1 2017 Q2 2017 $4.38 $3.06 Q1 2017 Q2 2017 $5.69 $3.08 Q1 2017 Q2 2017

Unit cost improvement

Big Fundamental 4-52 1H Russell 6H & Stephens 2H

Adjusted EBITDAX1 ($ mm)

$36.4 $63.1 Q1 2017 Q2 2017

GP&T ($/Boe)

$3.16 $2.74 Q1 2017 Q2 2017

Production growth Cash flow / income growth Net income2 ($ mm)

$9.8 $20.8 Q1 2017 Q2 2017 $15.74 $12.70 Q1 2017 Q2 2017

DD&A ($/Boe)

57% 59% % oil of total production

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SLIDE 5

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Industry leading well results in Reeves County

Publicly released well results since Q4 2016

Source: Company presentations and press releases since Q4 2016 (1) Includes CDEV Reeves County well results released in connection with 2Q17 earnings, 1Q17 earnings and 4Q16 earnings (2) Reeves County peer group includes: CXO, EOG, FANG, NBL, OXY, PDCE, REN, WPX and XEC

179 359 359 258 247 188 204 194 188 165 155 155 Russell 6H Stephens 2H Sieber Trust 4H Big Fundamental 4-52 1H CWI State 7H Parker 1H Ninja 1H Balmorhea State 2H Pop 4-59 1H Hightower State 2H Samurai 1H Collins 2H

Single section laterals (<5,000’) Extended laterals (>5,000’)

CDEV / offset operator Reeves County well results (IP-30 Bo/d / 1,000’) Centennial Reeves County well locator map

Big Fundamental 4-52 1H

Represents well results that have been highlighted in

  • ffset operator investor

presentations / press releases since Q4 2016 Centennial1 Public offset operators2

Parker 1H Sieber Trust 4H CWI State 7H Ninja 1H Samurai 1H Pop 4-59 1H Russell 6H Stephens 2H Balmorhea State 2H Hightower State 2H Collins 2H Big Fundamental 4-52 1H

Single section laterals (<5,000’) Extended laterals (>5,000’) Q2 2017 announced well

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SLIDE 6

4 8 11 14 30 43 22 46 66 30 day 60 day 90 day 10 20 30 40 50 60 70 30 60 90 Cumulative oil production (Mbo), normalized to 4,500’ Days on production

Legacy

  • perator3

Private equity

  • perator2

6

Tangible results from new technical team on Silverback acreage

Note: Production data unadjusted for downtime; Operator classification based on Company that completed the horizontal well; percentage increase calculations may not re-calculate due to rounding (1) Includes production from 4 wells: Represents horizontal wells completed by Centennial (Big Fundamental 4-52 1H, Ninja 4-50 49 1H, Samurai 4-49 50 1H and Little Fundamental 4-52 2H) (2) Includes production from 8 wells: Represents horizontal wells completed by private equity operator (3) Includes production from 22 wells: Represents horizontal wells completed by legacy operator

Average cumulative oil production by operator on acquired Silverback acreage (MBo; normalized to 4,500’, includes all lateral lengths)

+53% +54% +54% Days on production

Operator evolution 2011 - 2014 2015 - 2016 2017 Centennial technical team1

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SLIDE 7

Stephens 2H Russell 6H Production Results Lateral length (ft.) 4,190 4,185 Zone WC UA WC UA IP 30 (Bo/d) 1,503 1,503 IP 30 (Boe/d) 1,953 1,750 % oil 77% 86% IP 30 / 1,000' (Bo/d) 359 359 Completion design Clusters / stage 15 15 Proppant (lbs/ft) 2,400 2,600

7

Russell and Stephens wells significantly outperforming our best well ever drilled as of Q1

10 20 30 40 50 60 70 80 90 10 20 30 40 50 60 Cumulative oil production (Mbo), normalized to 4,500’ Days on production

Centennial average: 2016-Q1 2017 (13 wells) Centennial average: Q2 2017 (16 wells) Big Fundamental 4-52 1H Russell 6H Stephens 2H

Single section laterals (<5,000’) cum. oil production (Mbo)

Big Fundamental ranked as the strongest Centennial

  • il well ever drilled as
  • f Q1 20171

Russell 6H and Stephens 2H

  • utperforming the Big

Fundamental by 30%+ Q2 average cum. oil production

  • utperforming legacy

results by 14%

Well locator and summary results

Russell 6H Stephens 2H Big Fundamental 4-52 1H 2016-Q1 2017 CDEV average Strong well results across CDEV position

Note: IP 30 data and % oil figures based on 2-stream production results (1) Based on normalized 60-day cumulative oil production

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SLIDE 8

Ninja 4-50 49 1H Samurai 4-50 49 1H Hightower State 2H Production Results Lateral length (ft.) 8,775 8,990 9,515 Zone WC UA WC UA WC UA IP 30 (Bo/d) 1,704 1,391 1,566 IP 30 (Boe/d) 3,140 2,672 1,951 % oil 54% 52% 80% IP 30 / 1,000' (Bo/d) 194 155 165 Completion design Clusters / stage 15 15 15 Proppant (lbs/ft) 2,400 2,200 2,400

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Recent extended laterals outperforming legacy results

Two section laterals (>8,000’) cum. oil production (Mbo) Well locator and summary results

Ninja 4-50 49 1H Samurai 4--49-50 1H

10 20 30 40 50 60 70 80 90 100 10 20 30 40 50 60 Cumulative oil production (Mbo), normalized to 9,500’ Days on production

Centennial average: 2016-Q1 2017 (4 wells) Centennial average: Q2 2017 (3 wells) Ninja 4-50 49 1H Samurai 4-49 50 1H Hightower State 2H Ninja 4-50 49 1H has produced greater than 1,000 Bo/d for over 90 days Production from recent wells

  • utperforming legacy

results by over 50% 2016-Q1 2017 CDEV average Hightower State 2H

Note: IP 30 data and % oil figures based on 2-stream production results

Samurai 4-49 50 1H Hightower State 2H

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SLIDE 9

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Summary Q2 2017 Financial Results

Financial summary ($mm)1

(1) Amounts may not sum due to rounding (2) Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States. Please see slide 15 for a reconciliation to net income, our most directly comparable financial measure calculated and presented in accordance with GAAP. (3) Net income attributable to common shareholders (4) Liquidity defined as cash, plus availability under the revolving credit facility

($ in millions, unless specified) Q2 2017 Q1 2017 % change Average Daily Production (Boe/d) 29,664 18,469 61% Average Daily Oil Production (Bo/d) 17,435 10,489 66%

% Oil 59% 57% –

Financial highlights Total Revenue $ 91.1 $ 61.1 49% Adjusted EBITDAX2 $ 63.1 $ 36.4 73% Net Income3 $ 20.8 $ 9.8 111% Unit Costs ($/Boe) Lease Operating Expense $ 3.06 $ 4.38 (30%) Gathering, Processing & Transportation $ 2.74 $ 3.16 (13%) Severance & Ad Valorem Taxes $ 1.75 $ 1.92 (9%) Cash G&A $ 3.08 $ 5.69 (46%) Depreciation, Depletion & Amortization $ 12.70 $ 15.74 (19%) Capital Expenditures Incurred Drilling & Completion $ 145.7 $ 89.4 63% Land and Other 17.1 9.2 86% Facilities, Seismic and Other 6.8 2.2 208% Total Capital Expenditures $ 169.6 $ 100.8 68% Total Debt Balance $35.0 $ -

  • Cash and Cash Equivalents
  • 54.9
  • Liquidity4

$ 314.1 $304.4

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SLIDE 10

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Superior leverage profile provides operational flexibility

Net Debt / Total Capitalization1

Source: Company filings and consensus estimates Note: Peer group includes: CPE, CXO, EGN, FANG, JAG, LPI, PE, and RSPP (1) CDEV, CPE, CXO, FANG and PE as of 6/30/17; remaining companies as of 3/31/17; pro forma for capital markets and A&D activity post 3/31/17

21% 19% 18% 18% 13% 12% 1% 0%

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 CDEV Peer 8

82%

Net Debt / 2017E EBITDAX1

3.0x 1.9x 1.8x 1.4x 1.3x 1.1x 0.8x 0.2x 0.0x

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 CDEV Peer 8

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SLIDE 11

Simplifying Centennial’s Equity Capital Base

(1) Share count does not include 8 million Private Warrants (2) Figure does not include Series B preferred shares issued to Riverstone as part of the transaction (3) Total shares outstanding as of August 3, 2017, excluding restricted stock (4) Represents CRD, NGP Follow-On and Celero, collectively

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183.5 36.5 6.2 26.1 23.5 275.8 Closing of Business Combination Silverback Acquisition Warrant redemption Series B Preferred Conversion GMT Acquisition Q2 2017

Evolution of shares outstanding (Class A & Class C)1

(10/11/16) (12/28/16) (4/06/17) (5/25/17) (6/08/17) (6/30/17)

▪ Key initiatives to-date:  Redemption of public warrants  Conversion of Series B preferred shares ▪ Current share structure:  257 million Class A Common shares  19 million Class C shares  8 million Private Warrants1

48% 45% 7% Public float Riverstone and affiliates Centennial contributors4 Ownership as June 30, 2017

3 2

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SLIDE 12

Post - GMT 2017 FY Guidance Updated 2017 FY Guidance Net Average Daily Production (Boe/d) 23,600 - 27,900 27,350 - 31,650 Oil Net Average Daily Production (Bo/d) 14,850 - 16,650 17,100 - 18,900 Production Costs (per Boe) Lease Operating Expense ($3.25) - ($3.75) ($3.25) - ($3.55) Gathering, Processing & Transportation ($3.10) - ($3.60) ($2.75) - ($3.25) Depreciation, Depletion, Amortization ($18.00) - ($20.00) ($14.00) - ($16.00) Cash General and Administrative1 ($3.00) - ($3.75) ($3.00) - ($3.50) Severance and Ad Valorem Taxes (% of revenue) 6% - 8% 6% - 7% Capital Expenditure Program ($MM) $535

  • $625

$535

  • $625

D&C Capital Expenditure $475 - $540 $475 - $540 Land $50 - $70 $50 - $70 Facilities, Seismic and Other $10 - $15 $10 - $15 Operated Drilling Program Wells Spud (Gross) 65

  • 75

65

  • 75

Wells Completed (Gross) 65

  • 75

65

  • 75

Updated FY 2017 guidance

12

Revised 2017 Guidance Summary

▪ Deferring addition of 7th rig, 6 rigs flat for second half of 2017 ▪ Production guidance increased  14% increase to mid-point daily oil production  15% increase to mid-point of average daily equivalent production ▪ All full year unit cost estimates reduced as a result of cost controls and growth in absolute volumes ▪ Full-year capital and well count guidance remains unchanged

Guidance summary

(1) Represents G&A expenses less equity based compensation expense, which Centennial does not estimate

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SLIDE 13

▪ Grow net oil production from 5,757 Bo/d in 2016 to 60,000 by 2020

▪ Become mid-cap technical leader in G&G and well completion technology ▪ Achieve above average competence in drilling technology and execution

▪ Evaluate Bone Spring Shale prospectivity across acreage ▪ Maintain one of the lowest net debt positions of all U.S. E&P companies ▪ Maintain clear, easy to understand financials

▪ Target up to $50-$70 million per year spend for acreage acquisitions ▪ Achieve lowest unit costs among peers – LOE and G&A ▪ Achieve 60,000 Bo/d average annual oil production Objective: Best equity performance of any U.S. Mid Cap E&P through 2020

13

Centennial 2020 Game Plan

Delivering investor returns through operational outperformance

2017 2018 2020

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SLIDE 14

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Centennial Resource Development Overview

Core Delaware Basin Pure-Play

(1) As of 12/31/2016 plus incremental GMT acquisition acreage / inventory (2) Represents gross horizontal drilling locations; for legacy Centennial assumes credit for the Upper and Lower Wolfcamp A, Wolfcamp B, Wolfcamp C and 3rd Bone Spring Sand; assumes no locations in Pecos County; for GMT assumes credit for the Avalon Shale, 2nd Bone Spring Sand, 3rd Bone Spring Sand and Wolfcamp A (3) As of 12/31/2016; does not include incremental proved reserves from GMT acquisition

Summary operational statistics

▪ Increased Q2 2017 average daily oil production volumes by 66% compared to Q1 2017; average daily oil equivalent volumes up 61% – Increased commodity mix from 57% oil to 59% oil from Q1 to Q2 2017 ▪ Increased midpoint of 2017 production guidance for total production and oil production by 15% and 14%, respectively ▪ Lowered full-year unit cost estimate guidance across all categories ▪ Closed the acquisition of the Northern Delaware Basin assets of GMT Exploration

  • n June 8, 2017

Q2 2017 highlights

Northern Delaware ▪ Net acres: 11,850 ▪ Inventory2: 255 locations ▪ 2H 2017 drilling plan: 1 rig Southern Delaware ▪ Net acres: 76,067 ▪ Inventory2: 1,951 locations ▪ 2H 2017 drilling plan: 5 rigs

Operational overview Q2 2017 actuals Total production (Boe/d) 29,664 Oil production (Bo/d) 17,435 % oil 59% Active operated rigs running (as of 6/30/17) 6 2017E production guidance (midpoint) Previous Revised 2017E production (Boe/d) 25,750 29,500 2017E oil production (Bo/d) 15,750 18,000 Acreage1 Total net acreage ~88,000 % Operated 84% Drilling inventory1,2 Gross horizontal drilling locations 2,206 Gross operated horizontal drilling locations 1,394 Proved reserves Total proved reserves at 12/31/16 (MBoe)3 82,959 % oil 56%

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SLIDE 15

Reconciliation of Adjusted EBITDAX to Net Income

15 Adjusted EBITDAX reconciliation ($ thousands)1

(1) Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States

Q2 2017 Q1 2017 Successor Adjusted EBITDAX reconciliation to net income: For the three months ended June 30, 2017 For the three months ended March 31, 2017 October 11, 2016 through December 31, 2016 Net income (loss) attributable to common shareholders $20,762 $9,823 ($8,081) Net income attributable to noncontrolling interest 2,436 884 (904) Interest expense 707 410 378 Income tax expense (benefit) 9,069

  • Depreciation, depletion and amortization

34,300 26,160 14,877 Abandonment expense (benefit) and impairment of unproved properties

  • (29)
  • Net (gain) loss on derivative instruments

(2,529) (3,759) 1,548 Net cash receipts (payments) on settled derivatives 273 (397) 1,054 Equity based compensation expense 2,318 2,610 1,333 Exploration expense 2,470

  • 844

Transaction costs 457 887 4,097 (Gain) loss on sale of oil and natural gas properties (7,191) (166) (24) Adjusted EBITDAX $63,072 $36,423 $15,122