EX-99.1 2 brymarch2019investorpres.htm EXHIBIT 99.1 brymarch2019investorpres
Investor Presentation March 2019 March 2019


 
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, hedging activities, capital investments, return of capital, improvement of recovery factors 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 us appear in Risk Factors in our current Annual Report on Form 10-K and other filings with the Securities and Exchange Commission. 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 availability of natural gas; * our ability to use derivative instruments to manage commodity price risk; * impact of environmental, health and safety, and other governmental regulations, and of current, pending or future 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. Except as required by law, 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 the average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $71.54 per Bbl ICE (Brent) for oil and NGLs and $3.10 per MMBtu NYMEX (Henry Hub) for natural gas at December 31, 2018. The volume-weighted average prices over the lives of the properties were $66.49 per Bbl of oil and condensate, $32.87 per Bbl of NGLs and $2.806 per Mcf. 1 March 2019


 
Disclaimer (Cont.) Material assumptions also include a consistent and stable regulatory environment; timely and available drilling 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 to available markets. While Berry believes that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and speculative and are subject to significant risks and uncertainties discussed above. 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. 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 less than those contained in these projections. Measures used in this presentation that are not presented in accordance with U.S. generally accepted accounting principles ("GAAP") are reconciled to the nearest GAAP measure. See appendix for reconciliation of Non- GAAP measures. Adjusted Net Income (Loss) and Adjusted EBITDA are not measures of net income (loss), Levered Free Cash Flow is not a measure of cash flow, and Adjusted General and Administrative Expenses is not a measure of general and administrative expenses, in all cases, as determined by GAAP. PV-10 is not the standardized measure of oil and gas prescribed by GAAP. Finding and Development cost ("F&D") and reserves replacement ratio are not GAAP measures. These measures are provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP or to the standardized measure of discounted future cash flows and should not be considered as an alternative to, or more meaningful than, the measures as determined in accordance with GAAP. These measures are supplemental non-GAAP financial measures used by management to analyze and monitor the operating and financial performance of our business, evaluate hedging needs, allocate capital, compare the results between periods without regard to our financing methods or capital structure and measure and evaluate the cost of replacing annual production and adding proved reserves; and also by external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items and the income tax expense or benefit of these adjustments using our effective tax rate. We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, and amortization; 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 costs and reorganization items. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense and dividends. We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-recurring restructuring and other costs and non-cash stock compensation expense. PV-10 represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and does not give effect to derivatives transactions. F&D Cost – All-In is calculated by dividing total costs incurred for the year as defined by GAAP by the sum of proved reserve extensions and discoveries, revisions of previous estimates, improved recovery and purchases of minerals in place for the year. F&D Cost – Program is calculated by dividing total costs incurred for the year as defined by GAAP by extensions and discoveries and improved recovery for the year. Reserves replacement ratio is calculated by dividing the sum of proved reserve extensions and discoveries, revisions of previous estimates, improved recovery and purchases and sales of minerals in place for the year by current year production. The amounts included in the calculations these measures were computed in accordance with GAAP. We exclude certain items listed above because they can vary widely and unpredictably in nature, timing, amount and frequency and stock compensation expense is non-cash in nature. Our computations may not be comparable to other similarly titled measures used by other companies and should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP. There is no guarantee that historical sources of reserves additions will continue performing as many factors fully or partially outside of management's control affect reserves additions. Management uses this measure to gauge results of its capital allocation. The F&D measures are limited in that reserves may be added and produced based on costs incurred in separate periods and other oil and gas producers may use different measures affecting comparability. 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. To generate the type curves, 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, and these wells are listed on slides 42-44 of Berry's July 2018 Investor presentation (available at berrypetroleum.com/Investors). These type curves were not relied upon by our independent reserves engineers to prepare their reports on our reserves and they have not reviewed the type curves included in this presentation. Investors are cautioned not to place undue reliance on our type curves - our actual production and ultimate recoveries may differ substantially. 2 March 2019


 
Introductory Overview of Berry Petroleum  Conventional properties in California, Utah and Colorado Map of Berry Assets1 — Q4 2018 Production: 85% Oil — Q4 2018 California Production: 100% Oil  Proven management team Oil — Established track record of leading public companies Gas NGL  Long production history and operational control Uinta Piceance — Shallow decline curves with highly predictable production profiles — Low-risk development opportunities  Extensive inventory of high-return drilling locations CA — 20 years2 of low risk, development opportunities  High average working interest (98%) and net revenue interest (89%) at Q4 UT CO  Largely held-by-production acreage (75%), including 99% of California at San Joaquin Q4 2018  Brent-influenced oil pricing dynamics in California 4Q18 Production by California 1P Reserves by Commodity 1P Reserves by Commodity 1P PV-10 Value by Area3 Commodity 2% 1% 6% 13% 19% 28.0 143 106 $2.2 bn MBoe/d MMBoe MMBoe 100 % 85% 80% 94% 100 % Oil Gas NGL Oil Gas NGL California Rockies Oil Gas NGL 1 Bubble size implies PV-10 value of reserves. | 2 Based on 2019 development pace. | 3 Please see the Appendix for non-GAAP reconciliations. 3 March 2019


 
Framework for Success Focus on Creating Long-Term Value Committed to our Strategy  Managing to value not to production or volume growth  Directing capital primarily to our oil-rich and low risk development opportunities in the San Joaquin Grow Value “Super” basin  Shifting capital away from Rockies today due to marketing issues; production profile and reservoir performance well understood  Capital program funded from levered free cash flow - today and into the future Levered Free Cash Flow  Can maintain current production and pay financial commitments including dividends and interest through the cycle  Returning capital to shareholders primarily via industry leading dividend and, to a lesser extent, Return of Capital share buyback program  Developed metrics that focus of improving operational efficiency, EH&S performance and improving inventory visibility Focus on Execution  Plan on a two-year budget cycle to adapt to changing business conditions as they arise 4 March 2019


 
Framework for Success Powered by Our Principals and Assets  Low production declines with stable operational costs influenced by Brent pricing creates high margins Highly Oil Weighted  Mix for 2019 will average 87% oil  Management believes we have over 20 years of high returning inventory Substantial Inventory  2018 third party reserve report shows our R/P ratio is 14.5 years and our reserve replacement ratio in California is 275%  Well results are generally predictable, repeatable and present lower risk than unconventional resource plays - decades of historical data Operational Control and Stable Cost Structure  Largest cost is steam at 40-45% of OPEX. We hedge purchased gas and gain efficiencies from our cogeneration facilities  In California, three large fields on westside of the San Joaquin Basin  Thermal recovery from heavy oil in shallow reservoirs Focused on Geography, Skill Sets and HSE  Generations of knowledge and experienced employees  Built a culture of “Safety First”  Committed to maintain low leverage through the price cycle Balance Sheet Strength  Fund all organic growth with levered free cash flow  Committed to return capital to shareholders 5 March 2019


 
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 Berry Sandstone Steam Flood Midland  The extensive history of development and production in 80% Eagle Ford STACK Other our California fields provides a high degree of Basins Bakken confidence and predictability 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%  The low declining nature of our development wells and 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 slide 2 for a note regarding Berry's type curves and slides 37-38 of Berry's July 2018 Investor Presentation (available at berrypetroleum.com/Investors) for more detailed information related to those curves. 6 March 2019


 
We Are Broadly Advantaged vs. Unconventional Resource Players Resource / Shale Players The Berry Benefit Production History Decades of History Still Learning  Production Declines Low High  IP Rates Lower Higher  Capital and Service Cost Higher Low Intensity (i.e. “Big fracs”)  S 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 7 March 2019


 
Focused on Our California San Joaquin Basin Assets Map of Operations 8 March 2019


 
2018 Drilling Results & California Production 2018 Drilling Program California Asset Map 80 76 69 San Joaquin Basin: 18.3 Mboe/D 60 57 • Midway Sunset: 10.6 Mboe/D • Belridge: 3.3 Mboe/D 40 • McKittrick: 1.7 Mboe/D 30 • Poso Creek: 2.7 Mboe/D Drill Count 20 Ventura Basin: 1.4 Bboe/D 0 • Placerita: 1.4 Mboe/D Q1 2018 Q2 2018 Q3 2018 Q4 2018 Sandstone Non-Thermal Diatomite Thermal Diatomite Rockies 2018 Drilling Results 150 California Rockies 200 175 125 D&C cost D&C cost 150 100 $300K - $500K $1,000K -$1,500K 125 75 100 75 Drill Count 50 50 25 25 Avg Avg Peak Rate (boepd) 0 0 Sandstone Non-Thermal Thermal Rockies Diatomite Diatomite 9 March 2019


 
Proved Reserves YE 2018 Results – D&M View of Assets California Reserve Reconciliation Replacement Metrics BRY California BRY California 300% 275 % 20 14.50 14.70 15 200% 114 10 % 100% R/P Ratio Years 5 0% 0 Reserves Total Proved Reserves to Replacement Ratio 1 Production Ratio Total Berry Reserve Reconciliation Reserves & Value 100% 94% 80% 74% 60% 40% 20% 0% Reserves PV10 California Rockies 1See Appendix for Non-GAAP reconciliations 10 March 2019


 
Significant California Inventory Tier 1 Additional 7,030 1,663 489 979 585 444 3,314 1,811 787 Additional 272 Upside Hill Diatomite Thermal Thermal Rockies Total Tier 1 Hill Diatomite Thermal Thermal Rockies Total Well Count / (Wells & Producers Incl. Injectors) (non-thermal) Diatomite Sandstones (non-thermal) Diatomite Sandstones  Extended San Joaquin development  Enhanced production California California techniques  Enhanced drilling and completion techniques  Cost / efficiencies upside 11 March 2019


 
California’s Oil Market is Isolated From Rest of Lower 48  There are no major crude oil pipelines connecting Refineries - Bay Area Crude Capacity Refinery Name California to the rest of the US. (MBbl/d) 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 Refinery Name (MBbl/d) P66 Santa Maria 42 Kern Oil Bakersfield 26 2017 Sources of Feedstock for California SJR Bakersfield 15 No Pipelines To ​Africa ​Other 1% 4% California Market ​California ​South 32% California + America² Alaska 22% (Domestic) Refineries - LA Area Crude Capacity = ~45 % Refinery Name (MBbl/d) Supply Waterborne ​Alaska Crude Imports Chevron El Segundo 269 13% ​Middle East¹ Andeavor Carson 257 24%  Refinery PBF Torrance 150 ​Canada ​Mexico P66 Wilmington 139 2% 2%  Petroleum Port Andeavor Wilmington 85 Valero Wilmington 85 Source: California Almanac 1 Largest Middle Eastern importers are Saudi Arabia, Iraq and Kuwait. | 2 Largest South American importers are Ecuador, Colombia and Brazil. 12 March 2019


 
California Runs on California Crude, With Plenty of Takeaway Capacity . Kern County oil production benefits from access to multiple, intra- state pipelines connecting Kern County producers to refineries in Kern County, the Bay Area and L.A. . 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 San Pablo Shell 210  Common Carrier Bay Area Bay Philips 66 P66 75  Common Carrier Line 20001  Common Carrier Plains 130 / 75 1 LA Line 63  Common Carrier M70/55 PBF 95  Proprietary 1 Plains Line 2000 and 63 currently operate as one line. 13 March 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 $80 acquisitions and bolt-ons, purchase debt in the open market, explore returning capital to shareholders $70 $60 Fund planned development program Dec. 2018, $58 $50 Sustain production*, Pay interest, pay current dividend $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 2019 14 March 2019


 
Key Company Highlights Q4 2018 Full-year 2018 79% directed to 88% directed to development capital $53 $148 development capital in in California MM Capital Expenditures MM California 76 Wells Drilled 232 85% Oil 82% Oil 78% in California 28.0 Production Mboe/D 27.0 73% in California $258 $82 1 MM Adjusted EBITDA MM 1See Appendix for Non-GAAP reconciliations 15 March 2019


 
Key Area Highlights (Excludes E. Texas) 2018 California 2018 Rockies1 93% from California $227 2 $19 MM Operating Income MM 100% Oil 19.7 Daily Production 6.7 88% in California $126 Capital Expenditures $17 74% in California 106 Proved Reserves 37 $2,027 $125 94% in California PV-103 MM MM 1 Excludes E. Texas 2Operating income includes oil, natural gas and NGL sales, offset by operating expenses, general and administrative expenses, DD&A, and taxes, other than income taxes. 3See Appendix for Non-GAAP reconciliations 16 March 2019


 
Berry Total Production ► California continues to be our focus with investment of 88% of 2018 development capital o California grew 11% year over year and 15% January to December 2018 o 2018 Total company production is 27.0 Mboe/D 40,000 Acquired Hill Interest Sold Hugoton 35,000 Added 3rd Sold E. TX Rig 30,000 25,000 20,000 BOE per Day 15,000 10,000 5,000 0 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 California Rockies Liquid Rockies Gas 17 March 2019


 
Strong Oil-Driven Cash Margins are Backed by a Stable Cost Structure Total Company Margin All-in Unhedged Realized Price ($/Boe): 53.32 57.05 58.33 55.57 25.81 20.72 26.46 22.64 ~$10/Boe to replace and 2.40 2.95 2.89 maintain 3.31 2.35 3.84 3.80 3.92 production 3.79 4.49 3.94 4.25 3.50 3.03 3.62 3.30 19.61 16.89 18.10 18.67 Q1 2018 Q2 2018 Q3 2018 Q4 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 marketing sales, as well as derivative settlements (received or paid) for gas purchases. 2 See Appendix for the reconciliation of the Non-GAAP financial measure Adjusted G&A. 18 March 2019


 
Our calculation of Levered Free Cash Flow (Hedged) 1 We define Operating Expenses as LOE, electricity expense, transportation expense, and marketing expense, net of electricity, transportation and marketing sales, as well as derivative settlements (received or paid) for gas purchases. See Appendix for a reconciliation to GAAP for Adjusted EBITDA, Adjusted G&A, and Levered Free Cash Flow 19 March 2019


 
Key 2018 Financial Metrics $$>$ $/ Debt/Proved Interest Leverage PV-10/Debt Reserves CROIC Coverage ($/Boe) 1.5x 7.2x 5.5x $2.75 20% Leverage ratio = Long-term Debt / Adj. EBITDA Interest coverage = Adj. EBITDA / Interest expense Proved Reserves and PV-10 estimates are based on SEC’18 prices of $71.50 Brent / $3.10 Henry Hub CROIC: Cash Returned on Invested Capital = (Net cash provided by operating activities before working capital + Interest + non-recurring items) divided by (Average Stockholder’s Equity + Average Debt) (See Appendix for a reconciliation to GAAP for Adjusted EBITDA, PV-10, and CROIC) 20 March 2019


 
Prudent & Proactive Commodity Price Risk Management High degree of margin visibility via proactive hedging program and cost stability Hedging Volumes in MMBls (MBbl/d) As of Feb 28, 2019 5.6 (15.3) 2.6 3.0 0 2019 2020 * Brent* Swaps $76.09 Brent Puts $57.90 2019 Gas hedging: 17.5 mmbtu/day at $2.68 on a weighted-average basis * Excludes Basis Swaps 21 March 2019


 
Revised 2019E Guidance1 • Reduced capital spending by $35 million or 14% with a little more than a 3% decrease in production • Eliminated spending in the Rockies, adjusted CA capital • Included CROIC ranges Category 2019E Guidance Low High Average Daily Production (MBoe/d) 28 31 % Oil ~ 87% Operating Expenses ($/Boe) $ 18.00 . $ 19.50 Taxes, Other than Income Taxes ($/Boe) $ 4.25 . $ 4.75 Adjusted General & Administrative Expenses ($/Boe) $ 4.25 . $ 4.75 Capital Expenditures ($ millions) $ 195 . $ 225 CROIC 18% . 24% 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. Berry cannot 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, Berry is unable to provide a reconciliation of these measures without unreasonable effort. 22 March 2019


 
Our Financial Policy  Target Net Debt to EBITDA of 1.5 – 2.0x or lower through commodity price cycles Prudent Balance Sheet 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 amounts via Meaningful Quarterly Dividend  Targeting an attractive dividend payout ratio  Fund maintenance & 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 23 March 2019


 
Concluding Remarks  Berry is a highly differentiated E&P company with a clear strategic, operational and financial vision Highly Differentiated from Public Conventional and Shale E&P Companies  Positive Levered Free Cash Flow Through the Cycle  Stable Oil-Weighted Asset Base  Long Inventory Life of Highly Economic Oil Locations  Predictable Cost Structure  Strategic and Organic Growth Opportunities  Benefit from Favorable West Coast Crude Pricing Dynamics  Strong Balance Sheet  Capable of Consistent Capital Return to Investors  24 March 2019


 
Appendix Berry's Poso Creek field, California 25 March 2019


 
Operational Areas – Focused in California Super Basin Corporate & Executive Office Division Offices Producing Assets Basin Boundary Uinta Basin San Joaquin Basin Bakersfield Southern San Joaquin Basin Piceance Basin E. Ventura Basin Dallas 26 March 2019


 
Key Operational Activities  Development is primarily in the San Joaquin Basin Notable California Development Programs in 2018  Three rigs through 2018 and an average of four rigs in 2019 Completed 30+ wells in the Hill Diatomite  Select Second quarter activity: reservoir  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 Drilled 37 wells & Sunset resulting in over 80 new separate completions brought online  Drilled 1 Green River/Wasatch producer in Utah 70+completions in Thermal Diatomite  Select Third quarter activity:  Brought the 2nd quarter thermal Diatomite wells online in Midway Sunset Drilled 37 horizontal  Completed 15 Hill Diatomite wells in South Belridge (8 producers, wells in Thermal 7 injectors) Sandstones  Drilled 12 horizontal wells in the thermal sandstone in Midway Sunset, including 7 in North Midway  Select Fourth quarter activity:  Completed an additional 18 Hill Diatomite producers in South Belridge (14 producers, 4 injectors)  Drilled 48 wells in thermal sandstone reservoirs at Midway Sunset, Oil Field Boundary McKittrick, Poso and S. Belridge, including 9 additional horizontal producers in Midway Sunset Active Berry Development  Drilled 8 and recompleted 13 thermal Diatomite wells in Midway Sunset  Drilled an additional 7 Green River/Wasatch producers in Utah 27 March 2019


 
Non-GAAP Reconciliation Adjusted EBITDA Unhedged The following tables present a reconciliation of the GAAP financial measures of net income (loss) and net cash (used in) provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA Unhedged. Twelve Months Ended Three Months Ended Three Months Ended Three Months Ended Three Months Ended December 31, 2018 December 31, 2018 September 30, 2018 June 30, 2018 March 31, 2018 Adjusted EBITDA (in thousands) Net income (loss) $ 147,102 $ 131,768 $ 36,985 $ (28,061) $ 6,410 Add (Subtract): Interest expense $ 35,648 $ 8,820 $ 9,877 $ 9,155 $ 7,796 Income tax expense (benefit) $ 43,035 $ 39,890 $ 7,683 $ (5,476) $ 939 DD&A and Accretion $ 86,271 $ 24,253 $ 21,729 $ 21,859 $ 18,429 Derivative (gains) losses $ (1,735) $ (131,637) $ 17,115 $ 78,143 $ 34,644 Net cash received (paid) for scheduled derivative $ (38,482) $ 8,679 $ (1,052) $ 28,261 $ (17,849) settlements Gains (losses) on sale of assets and other $ (2,747) $ (3,269) $ 400 $ 123 $ - Stock Compensation Expense $ 6,750 $ 3,249 $ 1,182 $ 1,278 $ 1,042 Restructuring/non-recurring costs $ 6,773 $ 1,414 $ 1,598 $ 1,714 $ 2,047 Reorganization items $ (24,690) $ (1,498) $ (13,781) $ (456) $ (8,955) Adjusted EBITDA $ 257,925 $ 81,669 $ 81,736 $ 50,018 $ 44,503 MBOE 9,855 2,571 2,520 2,407 2,356 Adjusted EBITDA per BOE $ 26.17 $ 31.76 $ 32.43 $ 20.78 $ 18.89 28 March 2019


 
Non-GAAP Reconciliation Adjusted EBITDA Unhedged The following tables present a reconciliation of the GAAP financial measures of net income (loss) and net cash (used in) provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA Unhedged. Year Ended December 31, 2018 Net cash provided (used) by operating activities $ 103,100 Add (Subtract): Cash interest payments 19,761 Cash income tax (receipts) payments (1,901) Cash reorganization item (receipts) payments 832 Non-recurring restructuring and other costs 6,773 Derivative early termination payment 126,949 Other changes in operating assets and liabilities 2,410 Other, net — Adjusted EBITDA $ 257,924 Net cash (received) paid for scheduled derivative settlements 38,482 Adjusted EBITDA unhedged $ 296,406 29 March 2019


 
Non-GAAP Reconciliation - Levered Free Cash Flow Quarter Ended Year Ended December 31, December 31, ($ thousands) 2018 2018 Adjusted EBITDA $ 81,669 $ 257,924 Subtract: Capital expenditures - accrual basis (53,326) (147,831) Interest expense (8,820) (35,648) Dividends (9,992) (28,658) Levered free cash flow $9,531 $45,787 Net cash (received) paid for scheduled derivative settlements (8,679) 38,482 Levered free cash flow unhedged $ 852 $ 84,269 Total Mboe 2,571 9,855 Per BOE $ 3.71 $ 4.65 30 March 2019


 
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. Berry Petroleum Corporation Adjusted G&A calculation (Unaudited) Twelve Months Three Months Three Months Three Months Three Months Ended Ended Ended Ended Ended December 31, December 31, September 30, June 30, March 31, 2018 2018 2018 2018 2018 (in thousands, except per BOE amounts) G&A expense $ 54,026 $ 16,130 $ 13,429 $ 12,482 $ 11,985 less: Non-recurring restructuring costs $ (6,773) $ (1,414) $ (1,598) $ (1,714) $ (2,047) less: Stock compensation expense (G&A portion) $ (6,585) $ (3,183) $ (1,125) $ (1,260) $ (1,019) Adjusted G&A $ 40,668 $ 11,533 $ 10,706 $ 9,508 $ 8,919 MBOE 9,855 2,571 2,520 2,408 2,356 Adjusted G&A per BOE $ 4.13 $ 4.49 $ 4.25 $ 3.94 $ 3.79 31 March 2019


 
Non-GAAP Reconciliation - Cash Return on Invested Capital Twelve Months Ended December 31, 2018 (in thousands) Cash Return on Invested Capital: Net cash provided by operating activities $ 103,100 Subtract: Changes in working capital (8,658) Add: Interest expense 35,648 Cash payments on early-terminated derivatives 126,949 Non-recurring restructuring and other costs 6,773 Cash return $ 263,812 Divided by: Avg. Stockholder’s Equity + Avg. Debt 1,318,271 CROIC 20% Note: Stockholder’s Equity plus Debt is an average of the current and prior periods 32 March 2019


 
33 Non GAAP Reconciliation for PV-10 At December 31, 2018 (in millions) California PV-10 $ 2,027 Rockies PV-10 125 Total Company PV-10 2,152 Less: present value of future income taxes discounted at 10% (390) Standardized measure of discounted future net cash flows $ 1,762 33 March 2019


 
Non-GAAP Reconciliation - Reserve Replacement and Costs Total Company California (in MMBoe, except ratio and cost amounts) Extensions and discoveries (B) 22.4 19.3 Revisions of previous estimates (10.1) (0.4) Purchases of minerals 0.9 0.9 Organic changes (C) 13.2 19.8 Sales of minerals (2.0) — Total reserves changes 11.2 19.8 Production 9.9 7.2 Reserve replacement ratio 114% 275% Costs incurred (development costs)(A) ($ millions) $143.0 Finding & Development costs per Boe All-In (A)/(C) $10.83 Program (A)/(B) $6.38 (a) All costs incurred in 2018 were development costs. 34 March 2019


 
Non-GAAP Reconciliation - Reserves and PV-10 December 31, 2018 California Rockies (San Joaquin (Uinta and Total and Ventura Piceance basins) basins) Proved developed reserves: Oil (MMBbl) 66 7 73 Natural Gas (Bcf) — 76 76 NGLs (MMBbl) — 1 1 Total (MMBoe)(a) 66 21 87 Proved undeveloped reserves: Oil (MMBbl) 40 2 42 Natural Gas (Bcf) — 85 85 NGLs (MMBbl) — — — Total (MMBoe)(a) 40 16 56 Total proved reserves: Oil (MMBbl) 106 9 115 Natural Gas (Bcf) — 161 161 NGLs (MMBbl) — 1 1 Total (MMBoe)(a) 106 37 143 PV-10 ($MM)(b) $2,027 $125 $2,152 (a) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2018, the average prices of ICE (Brent) oil and NYMEX (Henry Hub) natural gas were $71.53 per Bbl and $3.09 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1 on an energy equivalent basis.(b) For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “Non-GAAP Financial Measures and Reconciliations—PV-10.” PV-10 does not give effect to derivatives transactions. 35 March 2019


 
Thank you! berrypetroleum.com 36 March 2019