Investor Presentation January 2019 -. 1:' - �.- I·i L, ,���l_;:�--_ - - I '. ---=-
Disclaimer The information in this document includes forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business strategy, potential acquisition opportunities, other plans and objectives for operations, maintenance capital requirements, expected production and costs, reserves, hedgingactivities, capital investments and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. You can typically identify forward-looking statements by words such as aim, anticipate, achievable, believe, budget. continue. could, effort, estimate, expect, forecast, goal, guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective
nature of events or outcomes. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect our results of operations and financial position appear in Risk Factors in our final prospectus dated December 14, 2018 as filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended, on December 14, 2018 (the "prospectus"). Factors (but not necessarily all the factors) that could cause results to differ include among others: • volatility of oil, natural gas and NGL prices; • inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures and meet working capital requirements; • price and avaUabl/ity of natural gas; • our ability to use derivative Instruments to manage commodity price rlsk; • impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation; • uncertainties associated with estimating proved reserves and related future cash flows; • our inability to replace our reserves through exploration and development activities; • our ability to obtain permits and otherwise to meet our proposed drilling schedule and to successfully drill wells that produce oil and natural gas in commercially viable quantities; • effects of competition; • our ability to make acquisitions and successfully integrate any acquired businesses; • market fluctuations in electricity prices and the cost of steam; • asset impairments from commodity price declines; • large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies; • geographical concentration of our operations; • our ability to improve our financial results and profitability following our emergence from bankruptcy and other risks and uncertainties related to our emergence from bankruptcy; • changes in tax laws; • impact of derivatives legislation affecting our ability to hedge; • ineffectiveness of internal controls; • concerns about climate change and other air quality issues; • catastrophic events; • litigation; • our ability to retain key members of our senior management and key technical employees; and • information technology failures or cyber attacks. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made. All included forward-looking statements, expressed or implied, are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. This presentation includes management's projections of certain key operating and financial metrics, Key assumptions underlying these projections include, but are not limited to forecasted average ICE (Brent) oil sales prices based on strip pricing as or May 31, 2018 of $74.59, S72.9B and S69.15 per Bbl for 2018, 2019, and 2020, respectively, and flat pricing assumption for 2021 onward of S66.49 per Bbl, and forecasted average NYMEX Henry Hub natural gas sales prices based on strip pricing as of May 31, 2018 of $2.94, $2.75 and S2.68 per Bbl for 2018, 2019, and 2020 respectively and flat pricing assumpUon for 2021 onward of $2.66 per Mel. - �� Berry- • - c: :� Petroleum Corpor�t_iq�- January 2019 - J
Disclaimer (Cont.) MateriaJ assumptions also include a consistent and stable regulatory environment; timely and available drllling and completion equipment and crew availability and access to necessary resources for drilling, completing and operating Wells: availability of capital; and accessibility to transport and sell oil and natural gas product 10 available markets. These projections renect the consistent application of Berry's accounting policies.While Berry believes that these assumpftons are reasonable in light of management's current expectations concerning future events, the estimates underlying these assumptions are inheren1ly uncertain and speculative and are subject to signfficant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results 10 differmaterially tram those Berry anticipates and many of which are beyond Berry's control. Any of the risks discussed in the prospectus would cause Berry's actual operating and financial results to vary significantly from the estimates provided herein. While Berry currently expects that its actual results will be within the ranges described herein, there will be differences between actual and projected results, and actual results may be materially greater or materially less than those contained in these projections. Inclusion of these projections in this presentation should not be regarded as a representation by any person that the projected operating and financial results will be achieved. In addition, the projected results set forth below are not necessarily indicative of results Berry may achieve in any other period. This presentation has been prepared by Berry and includes market data and other statistical information from sources believed by it to be reliable, including independent industry publications, government publications or other published independent sources. Some data is also based on Berry's good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although Berry believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. Proved reserve data included in this presentation is based on a proved reserve report prepared by DeGoyler and MacNaughton ("D&M") as of December 31, 2017 and addendum prepared as of June 28, 2018 (the "D&M Reporf'). Unless otherwise noted or suggested by context, reserve estimates were prepared in accordance with current SEC rules and regulations regarding oil, natural gas and NGL reserve reporting. Berry uses PV-10, a supplemental financial measure that is not presented in accordance with U.S. generally accepted accounting principles ("GAAP"), in this presentation, which reflects the present value of its estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization expense, exploration expenses and hedging activities, discounted at 10% per year before income taxes. Please see slide 27 for a reconciliation to the standardized measure of discounted future net cash flows. Berry uses Adjusted EBITDA and Levered Free Cash Flow, financial measures that are not presented in accordance with GAAP, in this presentation. Adjusted EBITDA and Levered Free Cash Flow are used as supplemental non-GAAP financial measures by Berry's management and by external users of Berry's financial statements, such as industry analysts, investors. lenders and rating agencies. Berry believes Adjusted EBITDA is useful because it allows management to more effectively evaluate Berry's operating performance and compare the results of its operations period to period without regard to Berry's financing methods or capital structure. Levered Free Cash Flow is used by management as a primary metric to plan capital allocation for maintenance and internal growth opportunities, as well as hedging needs. It also serves as a measure for assessing our financial performance and our ability to generate excess cash from operations to service debt and pay dividends. Berry defines Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, amortization and accretion; exploration expense: derivative gains or losses, net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense and other unusual out-of-period and infrequent items, including restructuring and reorganization costs. Berry defines Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense, and dividends. While Adjusted EBITDA and Levered Free Cash Flow are non-GAAP measures, the amounts included in these calculations were computed in accordance with GAAP. These measures are provided in addition to, and not as an alternative ·for, Income and liquidity measures calculated Tn accordance with GAAP. Our computations of Adjusted EBITDA and Levered Free Cash Flow may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA and Levered Free Cash Flow should be read in conjunctlon with the information contained in our financial statements prepared in accordance with GAAP. Please see slide 24 and 25 for a reconciliations of Adjusted EBITOA and Levered Free Cash Flow to GAAP amounts. Berry uses Adjusted General and Administrative Expenses ("Adjusted G&A"), a supplemental financial measure that is not presented in accordance with GAAP, in this presentation. We define Adjusted G&A as general and administrative expenses adjusted for non-recurring restructuring and other costs and non-cash stock compensation expense. Management believes Adjusted G&A is a useful measure because it allows management to more effectively compare our performance from period to period. We exclude the items listed because these amounts can vary widely and unpredictably in nature, timing, amount and frequency and stock compensation expense is non-cash in nature. Adjusted G&A should not be considered as an alternative to, or more meaningful than, general and administrative expenses as determined in accordance with GAAP. Adjusted G&A may not be comparable to other similarly titted measures for other companies. Please see slide 26 for a reconciliation of Adjusted G&A to general and administrative expenses. The type curves provided in this presentation are prepared by Berry's internal reserves engineers by conducting a decline curve analysis of production results from Berry's wells to generate an arithmetic mean of historical production for each project. Berry relied on the production results through February 1, 2018 for its own wells that it submitted to the Division of Oil, Gas and Geothermal Resources of the California Department of Conservation ("DOGGR"), which results are publicly available at maps.conservation.ca.gov/doggr/wellfinder/#openModal, to generate the type curves, and these wells are listed on slides 42-44 of Berry's July 2018 Investor presentation (available at berrypetroleum.com/tnvestors). These type curves were not relied upon by D&M in preparing the D&M Report, and D&M has not reviewed the type curves included in this presentation. Investors are cautioned not to place undue reliance on Berry's type curves and Berry's actual production and ultimate recoveries may differ substantially. - C>I Berry· ..� Petroleum January 2019 corpqntttor.1 •£_-�
Introductory Overview of Berry Petroleum ■ Conventional properties in California, Utah and Colorado Map of Berry Assets1 - Q3 2018 Production: 81% Oil - Q3 2018 California Production: 100% Oil ■ Proven management team e Oil • Gas - Established track record of leading public companies NGL ■ Long production history and operational control e - Shallow decline curves with highly predictable production profiles - Low-risk development opportunities ■ Extensive inventory of high-return drilling locations 2 - 18+ years of low risk, development opportunities - High average working interest (97%) and net revenue interest (88%) at Q3 ■ Largely held-by-production acreage (75%), including 99% of California at Q3 2018 ■ Brent-influenced oil pricing dynamics in California 3Q18 Production by California 1 P Reserves by Commodity4 1 P Reserves by Commodity3 1P PV-10 Value by Area3 Commodity3 2% 1% 5% 27.4 115 95 $1.9 • Oil •Gas • NGL I •Oil ■Gas • California • Uinta • Piceance •Oil •Gas NGL I 11 Bubble size implies PV-10 value of reserves, I 2 Based on 2018 development pace. I 3 Prepared based on D&M Report using closing monthly futures prices as reported on the ICE (Brent) for oil and NGLs and NYMEX (Henry Hub) for natural gas on May 31, 2018. Please see slides 48-49 of Berry's July 2018 Investor Presentation (available at berrypetroleum.comllnvestors) for a comparison to SEC Pricing. Please see slide 2 for a note regarding the non-GMP financial measure PV-10. 14 Includes 300 Boeld of Utah inventorysales January 2019
The Berry Advantage ... A Differentiated Our Key Asset, Operational and Financial Advantages ... Opportunity in E&P Oil dominated, Top-tier corporate level /ow-risk returns conventional asset base trong a ance sheet and Joaquin Basin liquidity assets on west Long-term capital side efficient growth Long-lived I=._. , ' - i Brent-influenced � reserves with low , High deg-ree· of capital crude oil pricing and predictable I :flexibility with low dynamics Berry production ... Result in ... decline rates 1 breakeven oil prices : Petroleum l--------= - 41 - • - - - �-�I Corporation Abundant potential Stable strategic development opportunities and production in-basin cost structures 18+ years1 of identified high return oil drilling locations 1 Based on 2018 development pace. . �.,-- Berry. , · .. Petrole(:Jrf1 Cqrggr�\.iq11 January 2019 --- -!;;:LJ::!!!!
We Are Broadly Advantaged vs. Unconventional Resource Players I - - - - - - - - - - - - - - - -, I I Resource/ Shale Players The BerryBenefit Production History Decades of History Still Learning ✓ Production Declines Low High ✓ 'I IP Rates Lower Higher X Capital and Service Cost Higher Low Intensity (i.e. "Big fracs") ✓ Operating Cost Stability/ Stable Experiencing Inflation Predictability ✓ No Potential GOR Issues Yes (CA ~100% oil) ✓ Takeaway and Service No Yes Capacity Constraints (We service CA demand) ✓ Ability to Generate and Recurring returns of capital Return Capital for Yes uncommon historically and today ✓ Shareholders �---------------J Berry· · 7•• Petroleum� Corpor§!tioil January 2019 �5 --�·
Our Low Declining Wells and Production Base Mitigate "Treadmill" Conundrum Experienced in Unconventional Shale Plays ■ The decline rates from our new conventional oil wells in % of Initial Rate From Peak Production (New Wells) California are materially lower than those experienced in the top-tier U.S. oily shale plays 100% -Berry Hill Diatomite -Berry Sandstone Steam Flood I Midland Eagle Ford ■ The extensive history of development and production in 80% our California fields provides a high degree of STACK ._______ Bakken __, confidence and predictability I 60% ■ Our California wells produce little to no gas 40% ■ With shale well, there is limited visibility around long term production profiles, including EURs and GORs 20% r-----------------------------1 1 ■ The low declining nature of our development wells and 1 1 : PDPs result in a high degree of capital flexibility 0%-'------------------------- 0 12 24 36 48 60 Source: Berry internal database, Third-party Company Presentations Month Note: Berry Sandstone Steam Flood reaches peak production after approximately 12 months, Time period shown for Sandstone is shown from peak production and onward. The initial rate of production from peak production is determined using Berry's type curves, Please see slide2 for a note regarding Berry's type curves and slides 37-3B of Berry's July 201B Investor Presentation (available at berrypetroleum com/Investors) for more detailed information related to those curves. - -----=.- -- - . ·-. Berry_ · �.:• Petroleum,) Corpqrlitibn Januijty2019 __ .4-._:.:,__
Significant Inventory of High Return Development Opportunities � : :: ' Tier 1 ,1 Additional ,1 11 11 6,973 �-------------------1 870 I � J I ,1 793 t( 11 I .I� 424 ': IRRs1• 2 : 11 I 904 :,1, II � � I ,1 ii'1 ,1 585 9)"-' :11: ��e:I .E ,, .� 452 .� .�:: 1,860 £; 1 1 <>15 ,, f? I I � i!I -5e Q_ 777 4 Additional .._ c3 Upside §o,£: 311 Extended San Joaquin � � t1 ✓ development � � 1: Hill Diatom�e Thermal Thermal : Uinta Total Tier :: Hill Diatomite Thermal Thermal Uinta Piceance Total , 11 (non-thermal) Diatomite Sandstones, ,, (non-thermal) Diatomite Sandstones ✓ Enhanced production 1 I I 11 ''�------------�' ,,'�------------� techniques ✓ Enhanced drilling and San Joaquin San Joaquin completion techniques :ii I! �I I: i ✓ Cost I efficiencies upside LL! - - - - - - - - - - - - - - - - - - - - - - - - _.i:;:. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ I - - - - - - - - - - - - - - - - - - - 'IRRs based on Strip Pricing. Berry's Strip Pricing oil, natural gas and NGL reserves were determined using index prices for natural gas and oil, respectively, as of May 31, 2018 without giving effect to derivative transactions. The average future prices for benchmark commodities used in determining Berry's Strip Pricing reserves were $74.59 per Bbl for oil and NGLs for 2018, $72.98 for 2019, $69.15 for 2020 and $66.49 for 2021 thereafter, on the ICE (Brent), and $2.94 per MMBtu for natural gas for 2018, $2.75 for 2019, $2.68 for 2020 and $2.66 for 2021 thereafter, on the NYMEX Henry Hub. For a comparison to SEC Pricing, please see slides 48-49 in Berry's July 2018 Investor Presentation (available at berrypetroleum.comllnvestors) 1 2 IRRs calculated based on Berry's type curves and management's assumptions. Please see slide 2 for a note regarding Berry's typecurves and slides 37-38 of Berry's July 2018 Investor Presentation (available at berrypetroleum.com/lnvestors) for more detailed information related to those curves. .,·-..: Berry: . I r I • Petroleam· January 2019 1• �7 Corp·o. :r� -idJi9.f l'
Focused on Our California San Joaquin Basin Assets South Belridge SAN LUIS KERN OBISPO COUNTY COUNTY North Midway-Sunset Map of Operations California Asset Locator • NW SJB Berry Operated Oil Field Boundary D SE SJB Beny Operated Oil Field Boundary D Oil Field Boundary 0 10 20Miles W+E . - ._-... = Ber�y." j�L Petroleum 1 CorJiQr,ijtioA January 2019 - ___=s.
Upside Opportunities--- Low Risk, High Return Near-Term Upside Mid-Term Upside Locations California Uinta Extended Uinta Extended San Development (Hz, Vert) Joaquin Development .·-i.: Berry. ·:, Petroleum, Cqrpqf��pr.i January 201'9 - -------==----�·
California's Oil Market is Isolated From Rest of Lower 48 ■ There are no major crude oil pipelines connecting Refineries - Bay Area Crude Capacity RefineryName California to the rest of the US. (MBblld/ Chevron Richmond 245 ■ California refiners import -67% of supplies from Andeavor Golden Eagle 166 waterborne sources, including >50% from non-US Shell Martinez 156 sources driving prices to track closely to Brent (ICE) Valero Benicia 145 P66 Rodeo 78 1 ■ In 2017, -46% of supply came from the Middle East Refineries - San Joaquin/ Bakersfield 2 and South America Crude Capacity RefineryName (MBbVdJ P66 Santa Maria 42 Kern Oil Ba1<ersfield7 26 2017 Sources of Feedstock for California SJ R Bakersfield 15 Africa --------- --------- Other 1¾ 4% . . California + f'tt , • Alaska (Domestic) Refineries - LA Area Crude Capacity =~45% Refinery Name (MBblld) Supply Waterborne Crude Imports Chevron El Segundo 269 Andeavor Carson 257 ,M Refinery PBF Torrance 150 Canada Mexico P66 Wilmington 139 2% 2% Petroleum Port Andeavor Wilmington 85 I . ,. Valero Wilmington 85 .:. .... ":•'") Source: California Almanac 1 Largest Middle Eastern importers are Saudi Arabia, Iraq and Kuwait. I 2 Largest South American importers are Ecuador, Colombia and Brazil. Berry ,- _ _ · __ �-- Petrolecimr � 10 January 2019 Cors: ••- .-.-i<ir --c-�ati .- -.� o..... ""' l!l . ,- -·....
California Runs on California Crude, With Plenty of Takeaway Capacity - - ------- - LEGEND • Kern County oil production benefits from access to multiple, intra SF Bay Area Plpellnes state pipelines connecting Kern County producers to refineries in -- Chevron - KLM Pipeline Kern County, the Bay Area and LA - P66 - Phillips 66 Pipeline • 3 run north to the Bay Area and all are common carriers • 2 of the 3 pipelines that run south to L.A. are common carriers • Crude by rail is a permanent feature of supply, but volumes have been limited to date • The California oil market is insulated from the infrastructure bottlenecks in the rest of the North America (Permian, Canada) Approx. Capacity Pipeline Owner (MBbl/d) Description KLM CPL 90 Common Carrier cu • San Pablo Shell 210 Common Carrier cu • Philips 66 P66 75 ■ Common Carrier Line 20001 • Common Carrier •ei�- Plains 130 /75 :3 Line 631 • Common Carrier M70/55 PBF 95 ■ Proprietary 1 Plains Line 2000 and 63 currently operate as one line. � 11 January2019
Strong Oil-Driven Cash Margins are Backed by a Stable Cost Structure Total Company Margin All-in Unhedged � Realized Price ($/Boe): � . ' . $10/Boe to replace and l maintain production Ql 2018 Q2 2018 Q3 2018 1 . 2 ■OpEx Taxes, other than Income ■ AdJusted G&A Interest ■ Dividends ■ Excess Cash Margin 1 We define Operating Expenses as LOE, electricity expense, transportation expense, and marketing expense, net of electricity, transportation and marl<eting sales. 2 See slide 2 for a note regarding the Non-GAAP financial measure Adjusted G&A - . �c Berry:. . _ I�-- Petroleum· �12 corpqf�rio January 2019
We Have Significant Financial Flexibility Across Oil Price Scenarios Simple financial principles Applied rationally across and planned allocations ... the price cycle Jun.2014,$116 $120 $110 $100 Historical Brent Crude Pricing $90 Accelerate development program, pursue accretive acquisitions and bolt-ans, purchase debt in the open $80 market, explore returning capital to shareholders $70 $60 Fund pJanned development program Sustain production"' , Pay interest, pay current dividend $50 $40 $30 Jan.2016,$32 * We estimate ~$10 per Boe in annual capital to keep $20 production volumes flat over the next three years $10 $0 2013 2014 2015 2016 2017 2018 . -. ... ..- - Berry - �- .J PetroJeCJm1 corporatigrn January 2019 .. .. .. .
Prudent & Proactive Commodity Price Risk Management High degree of margin visibility via proactive hedging programand cost stability Hedge Volumes in MMBbls (MBbl/d) as of 09/30/2018 6.0 (16.9) '3.4 1.2 (12.9) 2.6 1.1 2018 2019 2020 ■Brent Swap Brent Call Brent Purchased Puts 2018 2019 2020 Brent Swap $74.82 $75.40 Brent Purchased Put $65.00 $65.00 Brent Call $80.00 Weighted Average \ $75.36 $69.56 $65.00 .. J Note: Prices are weighted average. -------------y----------- • Excludes Basis Swaps 1 Excludes deferred premiums. $70.18 Weighted Average 2 Through March 31, 2020 but averaged over 366 days. Note: In the second quarter 201 B we restructured our hedge position to reflect marl<et pricing at that time. Berry ... - ... :;-. -. Petroleum· 4 January 2019 1 � Cor:pqfalio.n. -� - . - �-
2019E Guidance(11 Category 2019E Guidance Low High Average Daily Production (MBoeld) 29 32 % Oil ~86% Operating Expenses ($/Boe) $ 17.00 $ 18.50 Taxes, Other than Income Taxes ($/Boe) $4.25 $4.75 Adjusted General & Administrative Expenses ($/Boe) $4.00 $ 4.50 Capital Expenditures ($ millions) $ 230 $ 260 1. See Slide 2 for disclosures regarding the risks related to forward-looking statements and an explanation of Adjusted General and Administrative Expenses. The GAAP financial measure, General and Administrative Expense is not accessible for Adjusted General and Administrative Expense on a forward-looking basis. Berrycannot reasonably predict the non-recurring items in General and Administrative Expenses. Because of the uncertainty and variability of the nature and amount of future adjustments, which could be significant, Berryis unable to provide a reconciliation of these measures without unreasonable effort. 1;.- '· Berf-}( �:; � � 15 Petr0Jet1m January 2019 Corp.of�ttom-· .
Our Financial Policy Prudent Balance Sheet ■ Target Net Debt to EBITDA of 1.5 - 2.0x or lower through commodity price cycles Management ■ Deleveraging will be achieved through organic growth and excess free cash flow Return Capital to Shareholders ■ Intend to return capital to shareholders quarterly in meaningful quantities via Meaningful QuarterlyDividend ■ Targeting an attractive dividend payout ratio ■ Strategy is to secure revenue stream to fund capital needs Long-Term Hedging ■ Hedge target is to cover operating expenses and fixed charges 2 years out ■ Fixing physical gas supply and pricing to correlate to the top line hedging program ■ Fund maintenance and organic growth opportunities while producing positive Levered Free Cash Flow Capital Spend ■ Use other sources of capital for acquisitions that support the long-term leverage profile ■ Maintain capital flexibility; we can and will cut capex in a downturn ----:- -=-�• Berry; _..-=. -. Petroleum Corp§f-�t.ion Januaf"i 2019 - - -·- . - --
Concluding Remarks ------� ■ Berryis a highly differentiated E&P company with a clear strategic, operational and financial vision ✓ Positive Levered Free Cash Flow Through the Cycle ✓ ' - . S�ble Oil-Weighted Asset Ba�e- . · ✓ _ _ ... _ : . _ Long Inventory Life of Highly Economic Oil Locations ✓ · · · Predictable Cost Structure ✓ Strategic and Organic Growth Opportunities ✓ ✓ Strong Balance Sheet ✓ ✓ Serr�,-� r:�: Petrole.ur:n �17 cor15or�tlon January 2019 . -� -1,. I
Appendix Berry's Poso Creek field, California - - - . ·.aetr:y Petr.oleur;n January2019 �18 G,qfgora'tion·- -
Our Large, Conventional and Diversified Asset Base is Oil-Weighted and Valuable - - May 2018 Strip Net May 2018 Proved 3Q18 Strip 1P Gross June 2018 1 1 2 Reserves Avg. Net 3Q18 PV-10 • Drilling Producing (MMBoe)/ Production6 %Oil ($m m)/% Avg. WI / Inventory Wells, 2Q18 Net Basin % PD (MBoe/d) Production of Total NRl3·4 (Identified) Gross4•5 Acreage -- -- , ... \-... ,,, -----, ; , ---' 115/ 71 % 27.4 f 81 % I ( $1,862 · 95% / 88 % ( 7,053 3,911 116,927 \ I ; � , ___ ., , ... ___ ...} ., ' .......-- -- } California 95/ 66% 19.5 100% $ 1,762 / 95% 99 %/ 94% 4,858 2,704 7,945 Uinta 15 / 100 % 5.1 44% $ 91 / 5% 85% / 78% 1,245 920 96,441 Piceance 3 / 100% 2.0 3% $ 4/ 0% 72 %/ 63% 870 170 8,008 2 / 100% 0.7 1% $ 5/ 0% 99 % / 74 % 80 117 4,53 3 'Prepared based on D&M Report using closing monthly futures prices as reported on the ICE (Brent) for oil and NGLs and NYMEX (Henry Hub) for natural gas on May 31, 2018. Please see slide 2 for a note regarding Berry's type cuNes and slides 37-38 of Berry's July 2018 Investor Presentation (ava/Jable at berrypetroleum.com/lnvestors) for more detailed information related to those cuNes and slides 48-49 for a comparison to SEC Pricing. I 2 Please see slide 2 for a note regarding the non-GAAP financial measure PV-10, I 3 Weighted average WI across active wells as of June, 2018 and weighted average NRI for through June 2018. I 4 Excludes 91 wells in the Piceance basin each with a 5% working interest and eleven wells in the Permian basin all with less than o. 1% working interest. I 5 Includes steam flood and water flood injection wells in California. I 6 Includes 300 Boeld of Utah inventory sales I 6 East Texas assets were sold on November 30,2018 - : .- - Be�ry . . :._-: : � � 19 P etroeuaw1 -" January 2019 CorporatjQ.Q - - - ----
Operational Areas - Focused in California Super Basin Corporate & Executive Office • Division Offices • Producing Assets D Basin Boundary Southern San Joaquin Basin E. Ventura Basin Dallas CalN'llfTMA&MtL.a<:atar:;.w�!:=..��I r -:J,,OII_F"'4bfUllr)'....,Openeo [_:J0,1�-�. I•• ---tw -.�-;;.=- Berry· --� . Petroletim'i �20 Corpqr:�tton J�nuary 2019 - ._-a....,._
Key Operational Activities ■ Development is primarily in the San Joaquin Basin Notable CA Planned Development Programs in 2018 ■ Added a third rig in California in April and expect three rigs Completing 40 wells ' <<> through 2018 and an average of four rigs in 2019 in the Hill Diatomite ■ Select Second quarter activity: , Drilled 16 horizontal wells in the thermal sandstone reservoirs in Midway-Sunset including one in North Midway Sunset , Drilled 29 and recompleted 23 thermal Diatomite wells in Midway Bringing 80+ new Sunset resulting in over 80 new separate completions completions online in Thermal Diatomite , Drilled 1 Green River/Wasatchproducer in Utah ■ Select Third quarter activity: , Began bringing the new thermal Diatomite wells online in Midway Sunset , Completed 15 Hill Diatomite wells in South Belridge (8 producers, 7 injectors) , Drilled 12 horizontal wells in the thermal sandstone in Midway Canoo Ph1n Nattc-� Sunset, including 7 in North Midway Lbnunen, S!i\N UIS OBISPO COUNTY 0 \)\1 }- ;,� ■ Select Fourth quarter planned activity: r .� � � .. , Complete an additional 25 Hill Diatomite producers in South \�r A_, D Belridge (22 producers, 3 injectors) LJOil Field Boundary , Continue drilling in thermal sandstone reservoirs at Midway Sunset, c:=J McKittrick, Poso and S. Belridge, including additional horizontal Active BerryDevelopment producers in Midway Sunset , Drilling and recompleting additional thermal Diatomite wells in Midway Sunset , Drill an additional 7 Green River/Wasatchproducers in Utah -- Berry�- -·� ··, � PetroleUffi �21 CorporatJon January2019 . . . . '.. ·• --:.?.'''
California and U.S. Energy Industry are Intertwined Top Crude Oil Producing States in Lower 48 (2017)1 ■ California overview California is the third largest crude oil producer in the 1, 300,000 U.S. Lower 48, after Texas and North Dakota 1 ]9111 1,200. ODO ,..._..,,.._., Kern County is the third largest oil producing 400,000 county in the U.S. Lower 482 C'.l 300,000 Energy consumption ranks among the highest in the 6 nation creating an inherent incentive to maintain and 200,000 grow a diverse energy production base 100,000 Several major oil and gas companies maintain significant operations in the region including: Chevron, 0 Exxon and Shell Chevron is California's largest producer and keeps its Global Headquarters there3 Top Crude Oil Producing Counties in Lower 48 (Feb 2018)2 14,000 ■ Total annual economic contribution by oil and gas4 12,000 Oil and gas extraction represents sizeable portion of 10,000 contribution 0 8,000 368,100 direct, indirect and induced jobs 6,000 $33 billion in total labor income 4,000 $148 billion in total output 2,000 ■ Over $26 billion in annual state and local tax revenue 0 contributed by oil and gas overall4 1 EIA 2017 Total Crude Oil Production. 2 DrillingEdge. 3 Chevron; 2017 Supplement to the Annual Report, p. 13. 4 Los Angeles County Economic Development Corporation; YE 2015. Berry . = Petroleem Corp-qf�t_ion �anuary2019 •·1' - =--::_ -• -�·
Non-GAAP Reconciliation Adjusted EBITDA & Adjusted EBITDA Unhedged The following tables present a reconciliation of the GMP financial measures of net income (loss) and net cash (used in) provided by operating activities to the non-GMP financial measures of Adjusted EBITDA and Adjusted EBITDA Unhedged. Nine Months Ended Nine Months Ended September 30, (in thousands) September 30, 2018 (in thousands) 2018 Adjusted EBITDA reconciliation to net income (loss): Adjusted EBITDA and Levered Free Cash Flow Net income (loss) $15,334 reconciliation Add (Subtract): to net cash provided (used) by operating activities: Interest expense 26,828 Net cash provided (used) by operating activities $7,334 Income tax expense (benefit) 3,145 Add (Subtract): Depreciation, depletion, amortization and accretion 62,017 Cash interest payments 19,199 Derivative (gain) loss 129,902 Cash income tax payments Net cash received (paid} for scheduled derivative settlements (47,161} Cash reorganization item (receipts) payments 1,007 (Gain) loss on sale of assets and other 522 Non-recurring restructuring and other costs 5,359 Stock compensation expense 3,502 Derivative early termination payment 126,949 Non-recurring restructuring and other costs 5,359 Other changes in operating assets and liabilities 16,408 Reorganization items, net (23,192) Other, net Adjusted EBITDA $176,256 Adjusted EBITDA $176,256 - '-�- ..-. Be�rY· . (-·- • · Petroleum 23 January 2019 Co. - -r -. po_· ·-=--,,•rati o ,-- ':. n �
Non-GAAP Reconciliation - Levered Free Cash Flow Levered free cash flow reflects our financial flexibility; and we use it to plan our internal growth capital expenditures. We define levered free cash flow as Adjusted EBITDA less capital expenditures, interest expense, and dividends. Levered free cash flow is our primary metric used in planning capital allocation for maintenance and internal growth opportunities as well as hedging needs and serves as a measure for assessing our financial performance and measuring our ability to generate excess cash from our operations afterservicing indebtedness. Nine Months Ended (in thousands) September 30, 2018 Adjusted EBITDA and Levered Free Cash Flow reconciliation to net cash provided (used) by operating activities: Adjusted EBITDA $176,256 Subtract: Capital expenditures - accrual basis (94,505) Interest expense (26,828) Cash dividends declared (18,732) Levered Free Cash Flow $36,191 Net cash received (paid) for scheduled derivative settlements 47,161 Levered Free Cash Flow unhedged $83,352 24 January2019 "
Non-GAAP Reconciliation - Adjusted General & Administrative Expenses The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses to the non-GAAP financial measures of Adjusted general and administrative expenses. Three Months Ended Three Months Ended Three Months Ended (in thousands except MBoe amounts) September 30, 2018 June 30, 2018 March 31, 2018 Adjusted General and Administrative Expense reconciliation to general and administrative expenses: General and administrative expenses $13,429 $12,482 $11,985 Subtract: Non-recurring restructuring and other costs (1,598) (1,714) (2,047) Non-cash stock compensation expense (1,125) (1,260) (1,019) Adjusted General and Administrative Expenses $10,706 $9,508 $8,919 Adjusted General and Administrative Expenses ($/MBoe) $4.25 $3.94 $3.79 Total MBOE 2,520 2,408 2,356 - ···-y Berry:: · .. · : Pet�Ql�Qrn.. Corpbft5!tt6n Janu�ry2019 25 �
Reconciliation for PV-10 PV-10 Reconciliation ($ in millions) At December 31, 2017 PV-10 $ 1,114 (-) Present value of future income taxes discounted at 10 % (137) Standardized measure of discounted future net cash flows $ 977 -�·- Berty ".�: .- ... Petroleum Coip���Jtora January2019 -�-�
Thank you! Berry Petroleum Corporation berrypetroleum.com BRY Nasdaq Listed .. --:-,· ■ Berr-y Petrolel:irrr 27 Corg9f.�!!9m January2019 � - =,.