EX-99.1 2 a201910118kexh991.htm EXHIBIT 99.1 a201910118kexh991
CALIFORNIA bry FOCUSED OIL DRIVEN Investor Presentation October 2019 BRY NasdaQ Listed October 2019


 
bry Disclaimer This presentation includes forward-looking statements involving risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations of 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 expectations, 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 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 all the factors) that could cause results to differ include: • volatility of oil, natural gas and NGL prices; • price and availability of natural gas; • 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; • changes in laws or regulations; • our ability to use derivative instruments to manage commodity price risk; • inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures and meet working capital requirements; • the 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 ability to replace our reserves through exploration and development activities; • untimely or unavailable drilling and completion equipment or crew unavailability or lack of access to necessary resources for drilling, completing and operating wells; • our ability to make acquisitions and successfully integrate any acquired businesses; and • market fluctuations in electricity prices and the cost of steam. Except as required by law, we undertake no responsibility to publicly revise our forward-looking statements after the date they are made. All forward-looking statements 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 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 ending December 31 which 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. 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. The type curves provided in this presentation are prepared solely by Berry’s internal reserve engineers without third-party verification, 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 April 2019 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. . Investors are cautioned not to place undue reliance on Berry’s type curves presented herein, and Berry’s actual production results and ultimate recoveries may differ substantially. Reconciliation of Non-GAAP Measures to GAAP Please see https://ir.berrypetroleum.com/non-gaap-reconciliations-to-gaap for non-GAAP reconciliations to GAAP measures and additional important information. 1 October 2019


 
bry Our Strategy • Focus on attractive organic growth through cycle Return capital to shareholders • Top quartile fixed dividend within E&P industry Share repurchases to manage dilution Debt reduction • Pursue accretive strategic growth opportunities • Maintain low leverage profile • Live out of Levered Free Cash Flow1 1 Levered Free Cash Flow = EBITDA – (Capex + Cash Interest + Dividends) Please see https://ir.berrypetroleum.com/non-gaap-reconciliations-to-gaap for non-GAAP reconciliations to GAAP measures and additional important information. 2 October 2019


 
bry Framework for Success Focus on Creating Long-Term Value Grow Value ‐ Managing value; not production or volume growth ‐ Directing capital to oil-rich and low risk development opportunities in the San Joaquin “Super” basin ‐ Assets respond to capital Return of Capital Returning capital to shareholders via industry leading dividend Levered Free Cash Flow ‐ Capital program funded from Levered Free Cash Flow - today and into the future ‐ Maintain current production and pay financial commitments including dividends and interest Execution ‐ Focus on improving operational efficiency, EH&S performance and inventory visibility ‐ Two-year budget cycle gives flexibility for changing business conditions as they arise 3 October 2019


 
bry Framework for Success Powered by Our Principles and Assets Highly Oil-Weighted ‐ Brent pricing + stable operational costs = High Margins ‐ Q2 2019 production ~86% oil Operational Control and Stable Cost ‐ ~20 years of high returning inventory1 Structure ‐ Well results are predictable, repeatable and have low risk ‐ Largest operational cost is steam, forecasted at ~45% .......... Focused on California, Skill Sets and HSE ‐ Hedging purchased gas .......... ..................... ‐ Three large California fields on the westside of San Joaquin ‐ Efficient cogeneration facilities ......... ........................................ Basin ‐ Berry controls its operations with 98% company-wide ....................... ::::::::::::. ‐ Thermal recovery from heavy oil in shallow reservoirs Working Interest ''i!!~i!llllll!!i• ‐ Generations of knowledge and experienced employees ‐ Safety First Culture Balance Sheet Strength ‐ Low leverage through the price cycle ‐ Fund all organic growth with levered free cash flow ‐ Return capital to shareholders Core Values 1 Based on 2019 development pace, and management’s expectations Please see https://ir.berrypetroleum.com/non-gaap-reconciliations-to-gaap for non- GAAP reconciliations to GAAP measures and additional important information 4 October 2019


 
bry Our Financial Policy Prudent Balance Sheet Management • ‐ Target Net Debt to EBITDA of 1.0 – 2.0x or lower through commodity price cycles ‐ Deleveraging through organic growth and excess free cash flow Return Capital to Shareholders via Meaningful Quarterly Dividend • ‐ Intend to return capital to shareholders in meaningful amounts ‐ Targeting an attractive dividend yield Capital Spend • ‐ Fund our base production organically while producing positive Levered Free Cash Flow ‐ Use other sources of capital for accretive strategic acquisitions that support the long-term leverage profile ‐ Maintain capital flexibility; we can, and we are committed to cut capex in a downturn 5 October 2019


 
bry Planning for Success in California Grasstops outreach Aggressive outreach team • Lobbyist in Sacramento • Well-known holistic energy expert for grasstops/grassroots Grassroots outreach communication strategy • Stratified voter outreach program • Voter and politician education program in final stages of development Engaging in all-energy discourse • Western States Petroleum Association (WSPA) • California Foundation on Energy and the Environment (CFEE) • California Economic Summit/Regions Rise Together initiative • Independent Petroleum Association of America (IPAA) Proactive Remediation Renewable Energy environmental Technology activities 6 October 2019


 
bry Berry Overview ◼ Conventional properties in California, Utah and Colorado — Q3’19E 29,600 boe/d up 7.7% compared to last quarter — California Production: 100% Oil • Oil • Gas • NGL ◼ Proven management team — Established track record of leading public companies ◼ Long production history and operational control — Shallow decline curves with highly predictable production profiles CA Uinta1 UT CO — Low-risk development opportunities ◼ Extensive inventory of high-return drilling locations — ~20 years2 of low risk, development opportunities ◼ High average working interest (98%) and net revenue interest (89%) at Q2 2019 1Piceance ◼ Largely held-by-production acreage (74%), including 99% of California at Q2 2019 ◼ Brent-influenced oil pricing dynamics in California San Joaquin1 2018 California 1P Reserves 3Q19 Production by Commodity 2018 1P Reserves by Commodity 2018 1P PV-10 Value by Area3 by Commodity 1% 1% 6% 12% 19% 29.6 143 106 $2.2 bn MBoe/d MMBoe MMBoe 100 % 87% 80% 94% 100 % Oil Gas NGL Oil Gas NGL California Rockies Oil Gas NGL 1 • • • 2 • • • • • • • • Bubble size implies PV-10 value of reserves. | Based on 2019 development pace, and management’s expectations 3 Based on year end reserves and SEC pricing as of December 31, 2018. See disclosures on page 2 for additional information and assumptions 2,3 Please see https://ir.berrypetroleum.com/non-gaap-reconciliations-to-gaap for non-GAAP reconciliations to GAAP measures and additional important information 7 October 2019


 
bry Focused on Our California San Joaquin Basin Assets South Poso Creek Belridge Population SAN LUIS KERN Density OBISPO COUNTY People/Sq Mile COUNTY 2,490 108 Kern LA County County Map of Operations SANTA BARBARA COUNTY VENTURA ~- COUNTY California Asset Locator l NW SJB Berry Operated Oil Field Boundary D SE SJB Berry Operated Oil Field Boundary CJ Oil Field Boundary N 0 10 20 M11es W+E s 8 October 2019


 
bry Kern County is a Top Oil Producer No. 5 Beachy Point Co. Alaska 11.0M barrels/mo. \ No. 1 McKenzie Co. North Dakota No.3 17.3M barrels/mo. Weld Co. Colorado 13.7M barrels/mo. TOP1O OIL PRODUCING No. STATES M barrels/mo. Lea Co. 1. Texas 149.7 New Mexico 2. North Dakota 42. 7 14.6M barrels/mo. 3. New Mexico 25.3 4. Oklahoma 18.0 No.6 5. Colorado 15.5 Eddy Co. 6. Alaska 15.4 New Mexico 7. California 10.0M barrels/mo. 8. Wyoming Midland Co. 9. Louisiana Texas 10. Utah Source County info: 12.SM barrels/mo. Chip Low, Lea Co. Fi nance Director Source State info: U.S. Department of Energy GRAPHIC BY DONITTA BLACK NEWS-SUN 9 October 2019


 
Proved Reserves bry YE 2018 Results – DeGolyer and MacNaughton View of Assets California Reserve Reconciliation 2018 Replacement Metrics 120.0 BRY California 19.3 0.9 0.0 105.8 ■ ■ ■ BRY ■ California 300% 100.0 -93.2 275% 20 80.0 -7.2 -0.4 ➔ LJ.J 14.50 14.70 0 15 co 60.0 - 200% 14% '(ear- over Year ~ ~ - 40.0 10 114% 20.0 100% R/P Ratio Years Ratio R/P 5 0.0 Production Extensions Sales 12/31 /2017 Revisions Purchases 12/31/2018 0% 0 Reserves Total Proved Reserves to Replacement1 Production Ratio Click to add text Total Berry Reserve Reconciliation 2018 Reserves & Value 160.0 100% 141.4 22.4 0.9 2.0 142.7 140.0 - 94% -9.9 80% 120.0 -10.1 ➔ LJ.J 100.0 - 74% 0 -1% year over year 60% co 80.0 ~ -- ~ 60.0 40% 40.0 20.0 20% 0.0 0% Production Extensions Sales 1 12/31/2017 Revisions Purchases 12/31 /2018 Reserves PV10 ■ California ■ Rockies 1 Please see https://ir.berrypetroleum.com/non-gaap-reconciliations-to-gaap for non-GAAP reconciliations to GAAP measures and additional important information Based on year end reserves and SEC pricing as of December 31, 2018. See disclosures on page 2 for additional information and assumptions 10 October 2019


 
bry San Joaquin Basin Production History Field Performance Responds to Investment CA Total - San Joaquin Basin WTI Price 1,200 $120 No investment in Conventional CA “Harvest” • Production grew two-fold as 1,000 I $100 majors invested in fields ~' during late ‘70s – early ‘80s .II I I II I I price rise 800 $80 11' I • Investment bypassed Significant investment I f I “conventional CA” during the in existing fields driven 600 $60 by price rise resource play revolution MBOPD • Opportunity to apply I ($/bbl (Nominal) technology and innovative oil 400 I $40 I\ I field practices to CA fields I ' \1 I I / I 200 $20 ,, I II I ' ~ \ 1 t Start of resource plays I (Barnett) 0 $0 1920 1925 1930 1935 1940 1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 DOGGR & EIA; Management Comments Year 11 October 2019


 
bry Drilling Results & California Production Low Capital per Well Wells Drilled 120 114 2019 Q3E California Production 100 96 82 80 76 69 60 57 San Joaquin Basin: 21.6 Mboe/D Est. 40 30 20 Ventura Basin: 1.3 Bboe/D Est. 0 Q1'18 Q2'18 Q3'18 Q4'18 Q1'19 Q2'19 Q3'19E ■ Sandstone ■ Non-Thermal Diatomite ■ Thermal Diatomite ■ Rockies 2018 Drilling Results 150 California Rockies 200 ) 175 125 • D&C cost1 D&C cost 150 100 boepd $300K - $500K $1,000K -$1,500K 125 75 100 75 50 Drill Drill Count 50 25 25 0 0 Avg Peak Rate ( Sandstone Non-Thermal Thermal Rockies • Diatomite Diatomite 12 1D&C = Drilling and Completion October 2019


 
bry Time to Peak Production Drilling % of 2019 Planned Facility Hook-up • 1 • # Single Well Package Wells Cyclic Steaming • Peak Production • • 14 boe/d 42% Sandstone Producer • Number of Wells •# • # Single Well Package - ---+ - ---+ - ---+ • 13% 38 boe/d Sandstone Injector • • # Typically in 16 Well Package Peak Production timing varies • • 40% Thermal Diatomite 48 boe/d (per Well) • # Single Well Package • 0%2 • 39 boe/d Non-Thermal • Diatomite • • Spud 180• Days 1 Planned drilling of new wells including 5% for delineation, observation, & service wells 2 Does not include 38 planned completions through Q3’19 13 October 2019


 
bry Type Curve Comparison Berry Hill Diatomite Thermal Diatomite Sandstone Steam Flood Midland Eagle Ford STACK Non-Berry Bakken 200 1,600 - 180 . .. 1,400 - 160 \~.. ,~ 1,200 - 140 ... Berry . Non-Berry ,.. 1,000 BOE/day - 120 \ :. BOE/day \ ~­ - 100 \ \. 800 \ ·. - 80 ', ·,. 600 ', '·• .... / - 60 ', ..... ,, '• ,------------------------------------------- 400 - 40 .... ........ , ..- ,., ......, .... , ...... , .... ,. ·· ···-···-···-···---::-------- --·-· - 200 - 20 --------- ---------------- - 0 0 ■ 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 Month Source: Company reserves database, public company presentations See disclosures on page 2 for additional information regarding reserve assumptions 14 October 2019


 
bry The Berry Advantage - Ease of Operations ~ BRY Resource / Shale Companies Decades of History ✓ Production History Still Learning Low ✓ Production Declines High Lower IP Rates ✓ Higher 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) ✓ No Takeaway and Service Yes (We service CA demand) ✓ Capacity Constraints Ability to Generate and Recurring returns of capital Yes Return Capital to uncommon historically ✓ Shareholders 15 October 2019


 
bry Significant California Inventory Tier 1 Additional 7,030 1,663 489 979 585 444 3,314 1,811 (Incl. Producers & Injectors)Producers(Incl. 787 - Additional 272 Upside Hill Diatomite Thermal Thermal Rockies Total Tier 1 Hill Diatomite Thermal Thermal Rockies Total Well Count (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 1 Please see https://ir.berrypetroleum.com/non-gaap-reconciliations-to-gaap for non-GAAP reconciliations to GAAP measures and additional important information 16 October 2019


 
bry California’s Oil Market is Isolated From Rest of Lower 48 - There are no major crude oil pipelines connecting California to the rest of the US. Advantaged Oil Pricing Refineries - Bay Area Crude Capacity Refinery Name (MBbl/d) California refiners import ~70% of supplies from Chevron Richmond 245 waterborne sources, including >50% from non-US Andeavor Golden Eagle 162 sources driving prices to track closely to Brent (ICE) Shell Martinez 156 Valero Benicia 145 P66 Rodeo 78 Refineries - San Joaquin / Bakersfield ~40% of supply comes -from OPEC+ Crude Capacity Refinery Name (MBbl/d) P66 Santa Maria 42 Kern Oil Bakersfield 26 SJR Bakersfield 15 2018 Sources of Feedstock- for California No Pipelines To California Market California Supply 28% Alaska Waterborne 12% Crude Imports Rail Refineries - LA Area Non-OPEC Crude Capacity 1% Refinery Name 17% (MBbl/d) Chevron El Segundo 269 Andeavor Carson 257 PBF Torrance 160 Non-OPEC ◼ Refinery • P66 Wilmington 139 California ◼ Petroleum Port Andeavor Wilmington 85 • Valero Wilmington 85 OPEC+ OPEC+ • 42% Source: Berry, California Almanac, EIA, DOGGR, Drilling Info, Bloomberg OPEC & Non-OPEC sources include Argentina, Brunei, Canada, Equatorial Guinea, Ghana, Kazakhstan, Mexico, Peru, Russia, Trinidad and Tobago, UK, Brazil, Saudi Arabia, Ecuador, Colombia, Iraq, Kuwait. 17 October 2019


 
bry We Have Significant Financial Flexibility Through the Price Cycle The Plan at Each Price $120 Jun. 2014, $116 >$60 $110 $100 Accelerate development Historical Brent Crude Pricing program, pursue accretive $90 acquisitions and bolt-ons, purchase debt in the open $80 market, explore returning $70 capital to shareholders + $60 >$50 <$60 $50 $40 Fund planned Price impacted period > development $30 program + Jan. 2016, $32 $20 >$45 $10 <$50 $0 Sustain production, 2013 2014 2015 2016 2017 2018 2019 Pay interest, pay current dividend 18 October 2019


 
bry Strong Oil-Driven Cash Margins are Backed by a Stable Cost Structure Q2 2019 Q1 2019 All-in Unhedged $54.83 $52.42 Realized Price ($/Boe) Excess Cash Margin Available for growth ~ 7.51 ~ 5.31 Protect the base ~ 10.00 ~10.00 3.89 4.02 Dividends 3.59 3.52 Interest 4.92 4.63 2 Adjusted G&A 4.54 3.23 Taxes, other than income taxes 20.38 21.71 OpEx1 Q2'19 Q1'19 1 We define operating expenses as lease operating expenses, electricity generation expenses, transportation expenses, and marketing expenses, offset by the third-party revenues generated by electricity, transportation and marketing activities, as well as the effect of derivative settlements (received or paid) for gas purchases. Taxes other than income taxes are excluded from operating expenses. 2 Please see https://ir.berrypetroleum.com/non-gaap-reconciliations-to-gaap for non-GAAP reconciliations to GAAP measures and additional important information 19 October 2019


 
bry Prudent & Proactive Commodity Price Risk Management Oil hedging volumes in MMBbl (~MMBbl / day) as of 9/30/2019 (16.4 MMBbl / day) 0.1 5.9 (20.3 MMBbl / day) 0.1 0.1 (2.0 MMBbl / day) 1.7 0.7 2019 2020 2021 Brent Swaps $70.20 $64.25 $58.50 Brent Calls 79.49 - - WTI Swaps 61.75 61.75 - Note: Excludes Basis Swaps 20 October 2019


 
bry Prudent & Proactive Commodity Price Risk Management Purchased Gas hedging volumes in MMBtu (~MMBtu/day) As of 9/30/2019 (53,000 MMBtu / day) 1,525 17,835 (58,000 MMBtu / day) 460 4,905 (2,500 MMBtu / day) 900 2019 2020 2021 Kern, Delivered $2.90 $2.88 $2.50 SoCal Citygate 3.80 3.80 - 21 October 2019


 
bry Berry’s Value Proposition Tools to Unlock Shareholder Value Organic Growth ✓ Strategic Growth □ Fixed Dividend ✓ Share Buybacks ✓ Debt Repurchases □ Other □ ✓ Tools in use today ■ 22 October 2019


 
bry Growth + Dividend = Total Return 1otal production grov<t\1 +Y2% .... 29.5 26.31 - Total estimated annual 12% production growth2 plus + MMBoe / day Current dividend yield3 5% plus + Net share buybacks4 4% Total Return 21% 2018 2019E 1 Excludes East Texas | 2 Based on midpoint of 2019 production guidance 3 Current dividend yield as of 10/9/2019 | 4 Buyback dilution of ~3.6mm shares 23 October 2019


 
bry Q2’19 Financial Metrics $$>$ $/ Debt / Interest PV-10 / Proved Leverage CROIC Coverage Debt Reserves ($/Boe) 1.3x 8.1x 5.4x $2.78 23% Leverage: Debt / TTM Adj. EBITDA Interest coverage = TTM Adj. EBITDA / TTM Interest expense Proved Reserves and PV-10 estimates are based on SEC’18 prices of $71.50 Brent & $3.10 Henry Hub as of 12/31/2018 CROIC: TTM 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 Net Debt) Please see https://ir.berrypetroleum.com/non-gaap-reconciliations-to-gaap for non-GAAP reconciliations to GAAP measures and additional important information 24 October 2019


 
bry Reconciliation of Non-GAAP Measures For reconciliations of Non-GAAP to GAAP measures and other important information see https://ir.berrypetroleum.com/non-gaap-reconciliations-to-gaap 25 October 2019


 
bry Appendix 26 October 2019


 
bry Q2 2019 Q1 2019 Key Company Highlights Capital Expenditures $57mm $49mm Wells Drilled 114 96 100% California development 100% California development Production Mboe/d 27.4 27.8 86% Oil 86% Oil 76% California 76% California Adjusted EBITDA1 $63mm $69mm 1 Please see https://ir.berrypetroleum.com/non-gaap-reconciliations-to-gaap for non-GAAP reconciliations to GAAP measures and additional important information 27 October 2019


 
bry California Rockies Q2 2019 Key Area Highlights Operating Income1 $48mm $1mm 98% California Daily Production Mboe/d 20.8 6.6 100% Oil 41% Oil Capital Expenditures $52 $1 Proved Reserves2 106 37 Mboe 74% California PV-102,3 $2,027mm $125mm 1 Operating income includes oil, natural gas, and NGL sales, offset by operating expenses, general and administrative expenses, DD&A, and 94% California taxes other than income taxes 2 Proved Reserves and PV-10 as of 12/31/2018 3 Please see https://ir.berrypetroleum.com/non-gaap-reconciliations-to-gaap for non-GAAP reconciliations to GAAP measures and additional important information 28 October 2019


 
bry Kern Delivered Gas Monthly Average Price 9.00 Anomalous price spike impacted OpEx in Q1’19 6.00 4.94 ~ 75% of Fuel Gas Hedged at 4.15 Avg $3/mmbtu mmbtu for 18 Months $ / $ 3.00 2.78 Actual Kern Delivered Price 2014 2015 2016 2017 2018 2019 2020 BRY fuel gas price 0.00 Q1’18 Q4’18 Q1’19 Average quarterly unhedged cost of fuel gas Future gas price spikes are managed I Purchased fuel contracts ¾ of fuel needs through October 2020 0 ~$3.00/mmbtu Source: Platts 29 October 2019


 
bry 2019 Drilling Results by Well Type 114 96 15 82 18 1 1 39 1 14 20 38 60 59 26 Q1 Q2 Q3E Delineation Thermal Diatomite Sandstone Sandstone Producers Producers Injectors Uinta 30 October 2019


 
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