ý
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
(State of incorporation or organization)
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81-5410470
(I.R.S. Employer Identification Number)
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Title of each class
Common Stock, par value $0.001 per share
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Trading Symbol
BRY
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Name of each exchange on which registered
Nasdaq Global Select Market
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Large accelerated filer ¨
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Accelerated filer ¨
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Non-accelerated filer ý
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Smaller reporting company ¨
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Emerging Growth Company ý
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•
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Extensive inventory of low geological risk identified drilling opportunities with attractive full-cycle economics, high operational control and a stable development and production cost environment provides capital flexibility. We expect our operations to continue to generate attractive rates of return and positive Levered Free Cash Flow, which, if sustained, would allow us to continue returning capital to stockholders, sustain current production levels and fund organic growth, among other things. For example, our PUD reserves in California are projected to average single-well rates of return of approximately 50% based on the assumptions used in preparing our SEC reserves report as of December 31, 2019. We operate approximately 95% of our producing wells and expect to operate a similar percentage of our identified gross drilling locations. In addition, a substantial majority of our acreage is currently held by production and fee interest, including 94% of our acreage in California. Our high degree of control over our properties gives us flexibility in executing our development program, including the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of production. Also, unlike our peers, who operate primarily in unconventional plays, our assets generally do not necessitate inventory-constrained and highly specialized equipment, which provides us relative insulation from service cost inflation pressures. Our high degree of operational control and relatively stable cost environment provide us significant visibility and understanding of our expected cash flows.
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•
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Stable, long-lived, oil-weighted conventional asset base with low and predictable production decline rates. The majority of our interests are in properties that have produced oil for decades. As a result, the geology and reservoir characteristics are well understood, and new development well results are generally predictable, repeatable and present lower risk than unconventional resource plays. The properties are characterized by long-lived reserves with low production decline rates, a stable development cost structure and low-geologic risk developmental drilling opportunities with predictable production profiles. The nature of our assets provides us with significant capital flexibility and an ability to hedge efficiently material quantities of future expected production. For example, our PDP reserves have an estimated annual decline rate of approximately 13% to 20% in the years between 2020 and 2025 based on total PDP Boe reserves as of December 31, 2019. Based on the assumptions underlying our PUD estimates, we estimate that we will require slightly more than $11 per Boe in annual capital expenditures to keep production volumes consistent each year over the next three years.
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•
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Brent-influenced crude oil pricing advantage. California oil prices are Brent-influenced as California refiners import approximately 73% of the state’s demand from outside the state, most of which comes from OPEC
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•
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Simple capital structure and conservative balance sheet leverage with ample liquidity and minimal contractual obligations. Since our 2018 initial public offering ("IPO"), our capital structure has consisted of common stock and 7.0% senior unsecured notes due February 2026 (the "2026 Notes"). As of December 31, 2019, we had $391 million of available liquidity, defined as cash on hand plus availability under our reserves-based lending facility we entered into on July 31, 2017 (as amended, the “RBL Facility”). In addition, we have minimal long-term service or fixed-volume delivery commitments. This liquidity and flexibility permit us to capitalize on opportunities that may arise to grow and increase stockholder value.
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•
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Experienced, principled and disciplined management team. Our management team has significant experience operating and managing oil and gas businesses across numerous domestic and international basins, as well as reservoir and recovery types. We use our deep technical, operational and strategic management experience to optimize the value of our assets and the Company. We are focused on the principles of growing Levered Free Cash Flows as well as the value of our production and reserves. In doing so, we take a disciplined approach to development and operating cost management, field development efficiencies and the application of proven technologies and processes new to our properties in order to generate a sustained life-cycle cost advantage.
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•
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Return capital to our stockholders. Our objective is to maintain a disciplined value creation and returns-focused approach to capital allocation in order to generate excess free cash flow. We have returned capital to our shareholders, primarily in the form of a quarterly dividend, since our first quarter as a public company and we continue to target an attractive dividend yield. Additionally, our stock repurchase program approved by our Board of Directors in December 2018 provides an additional opportunity to return value to our existing shareholders. As of December 31, 2019, we repurchased approximately 6% of our outstanding shares for approximately $50 million and in February 2020 the Board authorized us to repurchase an additional $50 million of stock. If commodity prices increase for a sustained period of time, we would consider repaying debt obligations or returning additional capital to stockholders. For a discussion of our dividend policy, as well as our stock repurchase program, please see “Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”
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•
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Grow production and reserves in a capital efficient manner while producing positive internally generated Levered Free Cash Flow. We intend to allocate capital in a disciplined manner to projects that will produce predictable and attractive rates of return. We plan to direct capital to our oil-rich and low-geologic risk development opportunities while focusing on leveraging capital efficiencies across our asset base with the primary objective of internally funding our capital budget and growth plan. We may also use our capital flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically improve our positions in existing basins.
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•
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Maintain balance sheet strength and flexibility through commodity price cycles. We intend to fund our capital program while producing positive internally generated Levered Free Cash Flow. Over time, we expect to maintain low leverage through organic growth and with excess Levered Free Cash Flow. Our objective is to achieve and maintain a long-term, through-cycle leverage ratio (as defined in our RBL Facility) between 1.0x and 2.0x, or lower.
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•
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Proactively and collaboratively engage in matters related to regulation, safety, the environmental and community relations. We seek to work closely with regulators and legislators throughout the rulemaking process to minimize adverse impacts that new legislation and regulations might have on our ability to maximize our resources and to mitigate adverse impacts to our permitting process. We have found constructive dialogue with legislative and regulatory agencies can help avert compliance and permitting issues. We also believe that running our operations in a manner that protects the safety and health of our employees and is in compliance with existing laws and regulations is not only the right way to run our business, but it helps us build and maintain relationships with the communities in which we operate as well as credibility with the relevant agencies governing our operations. With ultimate oversight by our Board of Directors, Environmental, Health & Safety (“EH&S”) considerations are an integral part of our day-to-day operations and are incorporated into the strategic decision-making process across our business.
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•
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Maximize ultimate hydrocarbon recovery from our assets by optimizing drilling, completion and production techniques and investigating deeper reservoirs and areas beyond our known productive areas. While we continue to utilize proven techniques and technologies, we will also continuously seek efficiencies in our drilling, completion and production techniques in order to optimize ultimate resource recoveries, rates of return and cash flows. We will continue to advance and use innovative EOR and other recovery techniques to unlock additional value and will allocate capital towards these next generation technologies where applicable. In addition, we intend to take advantage of underdevelopment in basins where we operate by expanding our geologic investigation of reservoirs on our acreage and adjacent acreage below existing producing reservoirs. Through these studies, we will seek to expand our development beyond our known productive areas in order to add probable and possible reserves to our inventory at attractive all-in costs.
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•
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Enhance future cash flow stability and visibility through an active and continuous hedging program. Our hedging strategy is designed to insulate our capital program from price fluctuations by securing price realizations and cash flows for production. We also seek to protect our operating expenses through fixed-price gas purchase agreements and other hedging contracts. We have protected a significant portion of our anticipated crude oil production realizations and gas purchases through 2020 and have begun to hedge anticipated crude oil production and gas purchases for 2021. We will review our hedging program continuously as conditions change.
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2020 Budget
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2019 Actual
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(in millions)
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California
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$
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113-130
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$
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192
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Utah
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4-5
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10
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Colorado
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1-2
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1
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Corporate
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7-8
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8
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Total
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$
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125-145
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$
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211
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•
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Northwest San Joaquin operations: (i) our McKittrick Field property, which is a newer steamflood development with potential for infill and extension drilling; (ii) our South Belridge Field Hill property, which is characterized by two known reservoirs with low geological risk containing a significant number of drilling prospects, including downspacing opportunities, as well as additional steamflood opportunities; (iii) our thermal North Midway-Sunset Diatomite properties, where we utilize innovative EOR techniques to unlock significant value and maximize recoveries; and (iv) our North Midway-Sunset sandstone properties, where we use cyclic and continuous steam injection to develop these known reservoirs.
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•
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Southeast San Joaquin operations: (i) our South Midway-Sunset, properties, which are long-life, low-decline, strong-margin thermal oil properties with additional development opportunities; (ii) our Poso Creek property, which is an active mature shallow, heavy oil asset that we continue to develop across the property; and (iii) our Placerita property, which is a mature shallow, heavy oil asset with additional recompletion opportunities.
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Average Net Daily Production(1)
for the Year Ended
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December 31, 2019
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December 31, 2018
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(MBoe/d)
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Oil (%)
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(MBoe/d)
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Oil (%)
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California
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22.6
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100
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%
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19.7
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100
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%
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Utah
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5.0
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54
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%
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5.0
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48
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%
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Colorado
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1.4
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2
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%
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1.7
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1
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%
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East Texas(2)
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—
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—
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%
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0.6
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—
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%
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Total
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29.0
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87
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%
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27.0
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82
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%
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Year Ended
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December 31, 2019
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December 31, 2018
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Average daily production(1)(3):
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Oil (MBbl/d)
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25.3
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22.0
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Natural gas (MMcf/d)
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20.0
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26.3
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NGLs (MBbl/d)
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0.4
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0.6
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Total (MBOE/d)(2)
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29.0
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27.0
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(1)
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Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.
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(2)
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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, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1 on an energy equivalent basis.
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(3)
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On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
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Acreage
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Net Acreage Held By Production and Fee Interest(%)
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Producing Wells, Gross(2)(3)
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Average Working Interest (%)(3)(4)
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Net Revenue Interest (%)(3)(5)
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Identified Drilling Locations(6)
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Gross
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Net(1)
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Gross
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Net
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California
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18,517
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14,144
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94
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%
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3,014
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99
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%
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93
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%
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10,822
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10,785
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Utah
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123,665
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92,921
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70
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%
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943
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95
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%
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62
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%
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37
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29
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Colorado
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10,553
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8,008
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85
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%
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167
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83
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%
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79
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%
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—
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—
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Total
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152,735
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115,073
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80
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%
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4,124
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98
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%
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90
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%
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10,859
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10,814
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(1)
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Represents our weighted-average interest in our acreage.
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(2)
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Includes 658 steamflood and waterflood injection wells in California.
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(3)
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Excludes 90 wells in the Piceance basin each with a 5% working interest.
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(4)
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Represents our weighted-average working interest in our active wells.
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(5)
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Represents our weighted-average net revenue interest for the year ended December 31, 2019.
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(6)
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Our total identified drilling locations include approximately 1,289 gross (1,276 net) locations associated with PUDs as of December 31, 2019, including 123 gross (121 net) steamflood injection wells. Please see “—Our Reserves—Determination of Identified Drilling Locations” for more information regarding the process and criteria through which we identified our drilling locations.
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Proved Reserves as of December 31, 2019(1)
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Oil (MMBbl)
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Natural Gas (Bcf)
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NGLs (MMBbl)
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Total (MMBoe)(2)
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% of Proved
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% Proved Developed
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Capex(3) ($MM)
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PV-10(4) ($B)
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|||||||
PDP
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61
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|
39
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1
|
|
|
68
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|
49
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%
|
|
84
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%
|
|
54
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|
|
1.0
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PDNP
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13
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|
|
—
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|
|
—
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|
|
13
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|
10
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%
|
|
16
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%
|
|
30
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|
|
0.2
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PUD
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56
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|
|
6
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|
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—
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|
|
57
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|
41
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%
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|
—
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%
|
|
706
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|
|
0.6
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Total
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130
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|
|
45
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|
|
1
|
|
|
138
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|
100
|
%
|
|
100
|
%
|
|
790
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|
|
1.8
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
California
|
122
|
|
|
—
|
|
|
—
|
|
|
122
|
|
|
|
|
|
747
|
|
|
1.7
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(1)
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Our estimated net reserves were determined using 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 $63.15 per Bbl Brent for oil and natural gas liquids (“NGLs”) and $2.62 per MMBtu Henry Hub for natural gas at December 31, 2019. The volume-weighted average prices over the lives of the properties were estimated at $58.88 per Bbl of oil and condensate, $16.93 per Bbl of NGLs and $2.84 per Mcf of gas. The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market environment. Prices were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules, including adjustment by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Please see “—Our Reserves and Production Information—PV-10”.
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(2)
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Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
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(3)
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Represents undiscounted future capital expenditures estimated as of December 31, 2019.
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(4)
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PV-10 is a financial measure that is not calculated in accordance with GAAP. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “—Our Reserves and Production Information—PV-10”. PV-10 does not give effect to derivatives transactions.
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(1)
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Our estimated net reserves were determined using 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 $63.15 per Bbl Brent for oil and NGLs and $2.62 per MMBtu Henry Hub for natural gas at December 31, 2019. The volume-weighted average prices over the lives of the properties were $58.88 per Bbl of oil and condensate, $16.93 per Bbl of NGLs and $2.84 per Mcf. The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market environment. Prices were calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules including adjustments by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. For more information regarding commodity price risk, please see “Item 1A. Risk Factors—Risks Related to Our Business and Industry—Oil, natural gas and NGL prices are volatile and directly affect our results.”
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(2)
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Approximately 18% of proved developed oil reserves, 0% of proved developed NGL reserves, 0% of proved developed natural gas reserves and 16% of total proved developed reserves are non-producing.
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(3)
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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, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1 on an energy equivalent basis.
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(4)
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For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “—PV-10.” PV-10 does not give effect to derivatives transactions.
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At December 31, 2019
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||
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(in billions)
|
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California PV-10
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$
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1.7
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|
Utah PV-10
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0.1
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Colorado PV-10
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—
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Total Company PV-10
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1.8
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Less: present value of future income taxes discounted at 10%
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(0.3
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)
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Standardized measure of discounted future net cash flows
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$
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1.5
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California
(San Joaquin and Ventura basins)
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|
Utah
(Uinta basin)
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Colorado
(Piceance basin)
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Total
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||||
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(in MMBoe)(1)
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||||||||||
Beginning balance as of December 31, 2018
|
106
|
|
|
19
|
|
|
18
|
|
|
143
|
|
Extensions and discoveries
|
13
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|
|
—
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|
|
—
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|
|
13
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|
Revisions of previous estimates
|
11
|
|
|
(2
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)
|
|
(16
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)
|
|
(7
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)
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Purchases of minerals in place
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—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Current year production
|
(8
|
)
|
|
(2
|
)
|
|
(1
|
)
|
|
(11
|
)
|
Ending balance as of December 31, 2019
|
122
|
|
|
15
|
|
|
1
|
|
|
138
|
|
(1)
|
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, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1 on an energy equivalent basis.
|
|
California
(San Joaquin and Ventura basins)
|
|
Utah
(Uinta basin)
|
|
Colorado
(Piceance basin)
|
|
Total
|
||||
|
(in MMBoe)(1)
|
||||||||||
Beginning balance as of December 31, 2018
|
40
|
|
|
1
|
|
|
14
|
|
|
55
|
|
Extensions and discoveries
|
12
|
|
|
—
|
|
|
—
|
|
|
12
|
|
Revisions of previous estimates
|
13
|
|
|
1
|
|
|
(14
|
)
|
|
—
|
|
Reclassifications to proved developed
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
Ending balance as of December 31, 2019
|
55
|
|
|
2
|
|
|
0
|
|
|
57
|
|
(1)
|
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, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of approximately 4 to 1 on an energy equivalent basis.
|
|
PUD Drilling Locations
(Gross) |
|
Unproven Drilling Locations (Gross)
|
|
Total Drilling Locations (Gross)
|
||||||||||||
|
Oil and Natural Gas Wells
|
|
Injection
Wells |
|
Oil and Natural Gas Wells
|
|
Injection
Wells |
|
Oil and Natural Gas Wells
|
|
Injection
Wells |
||||||
California
|
1,129
|
|
|
123
|
|
|
8,099
|
|
|
1,471
|
|
|
9,228
|
|
|
1,594
|
|
Utah
|
37
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37
|
|
|
—
|
|
Colorado
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Identified Drilling Locations
|
1,166
|
|
|
123
|
|
|
8,099
|
|
|
1,471
|
|
|
9,265
|
|
|
1,594
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||
SJV Midway Sunset Field
|
|
|
|
|
|
|
|
|
||||
Total production(1):
|
|
|
|
|
|
|
|
|
||||
Oil (MBbls)
|
5,543
|
|
|
4,495
|
|
|
3,560
|
|
|
|
693
|
|
Natural gas (Bcf)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
NGLs (MBbls)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
Total (MBoe)(2)
|
5,543
|
|
|
4,495
|
|
|
3,560
|
|
|
|
693
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||
SJV Belridge Hill(3)
|
|
|
|
|
|
|
|
|
||||
Total production(1):
|
|
|
|
|
|
|
|
|
||||
Oil (MBbls)
|
1,312
|
|
|
1,196
|
|
|
609
|
|
|
|
35
|
|
Natural gas (Bcf)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
NGLs (MBbls)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
Total (MBoe)(2)
|
1,312
|
|
|
1,196
|
|
|
609
|
|
|
|
35
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||
Piceance
|
|
|
|
|
|
|
|
|
||
Total production(1):
|
|
|
|
|
|
|
|
|
||
Oil (MBbls)
|
*
|
|
*
|
|
14
|
|
|
|
2
|
|
Natural gas (Bcf)
|
*
|
|
*
|
|
3.6
|
|
|
|
0.8
|
|
NGLs (MBbls)
|
*
|
|
*
|
|
—
|
|
|
|
—
|
|
Total (MBoe)(2)
|
*
|
|
*
|
|
610
|
|
|
|
138
|
|
*
|
Represented less than 15% of our total proved reserves for the periods indicated.
|
(1)
|
Production represents volumes sold during the period.
|
(2)
|
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, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1.
|
(3)
|
In July 2017, we acquired the remaining 84% working interest in the South Belridge Hill property located in Kern County, California, in which we previously owned a 16% working interest.
|
|
California
(San Joaquin and Ventura basins) |
|
Utah
(Uinta basin) |
|
Colorado
(Piceance basin) |
|
Total
|
|||
Oil
|
|
|
|
|
|
|
|
|||
Gross(1)
|
2,504
|
|
|
986
|
|
|
—
|
|
|
3,490
|
Net(2)
|
2,479
|
|
|
937
|
|
|
—
|
|
|
3,416
|
Gas
|
|
|
|
|
|
|
|
|||
Gross(1)
|
—
|
|
|
—
|
|
|
176
|
|
|
176
|
Net(2)
|
—
|
|
|
—
|
|
|
125
|
|
|
125
|
(1)
|
The total number of wells in which interests are owned. Includes 610 steamflood and waterflood injection wells in California.
|
(2)
|
The sum of fractional interests.
|
|
California
(San Joaquin and Ventura basins) |
|
Utah and Other
(Uinta and Piceance basins) |
|
Total
|
Developed(1)
|
|
|
|
|
|
Gross(2)
|
9,835
|
|
94,268
|
|
104,103
|
Net(3)
|
9,289
|
|
72,103
|
|
81,392
|
Undeveloped(4)
|
|
|
|
|
|
Gross(2)
|
8,682
|
|
39,950
|
|
48,632
|
Net(3)
|
4,855
|
|
28,827
|
|
33,682
|
(1)
|
Acres spaced or assigned to productive wells.
|
(2)
|
Total acres in which we hold an interest.
|
(3)
|
Sum of fractional interests owned based on working interests or interests under arrangements similar to production sharing contracts.
|
(4)
|
Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether the acreage contains proved reserves.
|
|
California
(San Joaquin and Ventura basins) |
|
Utah
(Uinta basin)
|
|
Colorado
(Piceance basin)
|
|
Total
|
||||
2019
|
|
|
|
|
|
|
|
||||
Oil(2)
|
335
|
|
|
3
|
|
|
—
|
|
|
338
|
|
Natural Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2018
|
|
|
|
|
|
|
|
||||
Oil(1)
|
224
|
|
|
8
|
|
|
—
|
|
|
232
|
|
Natural Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2017
|
|
|
|
|
|
|
|
||||
Oil(1)
|
124
|
|
|
—
|
|
|
—
|
|
|
124
|
|
Natural Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
Includes injector wells.
|
(2)
|
Includes 50 wells that had not yet been connected to gathering systems in California.
|
|
|
|
|
|
|
|
|
|
|
Gross Drilling Locations(1)
|
|
State
|
|
Project Type
|
|
Well Type
|
|
Completion Type
|
|
Recovery Mechanism
|
|
Total
|
|
California
|
|
Thermal Sandstones
|
|
Vertical / Horizontal
|
|
Perforation/Slotted liner/gravel pack
|
|
Continuous and cyclic steam injection
|
|
6,143
|
|
California
|
|
Thermal Diatomite
|
|
Vertical
|
|
Short interval perforations
|
|
High-pressure cyclic steam injection
|
|
3,198
|
|
California
|
|
Hill Diatomite (non-thermal)
|
|
Vertical
|
|
Hydraulic stimulation, low intensity pin point
|
|
Pressure depletion augmented with water injection
|
|
1,481
|
|
Utah
|
|
Uinta
|
|
Vertical / Horizontal
|
|
Low intensity hydraulic stimulation
|
|
Pressure depletion
|
|
37
|
|
Colorado
|
|
Piceance
|
|
Vertical
|
|
Proppantless slick water stimulation
|
|
Pressure depletion
|
|
—
|
|
Total
|
|
|
|
|
|
|
|
|
|
10,859
|
|
(1)
|
We had 1,289 gross (1,276 net) locations associated with PUDs as of December 31, 2019 including 123 gross (121 net) steamflood injection wells. Of those 1,289 gross PUD locations, 1,252 are associated with projects in California, 37 are associated with the Uinta basin. Please see “—Our Reserves —Determination of Identified Drilling Locations” for more information regarding the process and criteria through which we identified our drilling locations. During the year ended December 31, 2019, we drilled 292 gross (292 net) wells that were associated with PUDs at December 31, 2018, including 25 gross (25 net) steamflood injection wells.
|
•
|
Establish air, soil and water quality standards for a given region, such as the San Joaquin Valley, and attainment plans to meet those regional standards, which may significantly restrict development, economic activity and transportation in the region;
|
•
|
require the acquisition of various permits before drilling, workover production, underground fluid injection, enhanced oil recovery methods, or waste disposal commences;
|
•
|
require notice to stakeholders of proposed and ongoing operations;
|
•
|
require the installation of expensive safety and pollution control equipment—such as leak detection, monitoring and control systems—to prevent or reduce the release or discharge of regulated materials into the air, land, surface water or groundwater;
|
•
|
restrict the types, quantities and concentration of various regulated materials, including oil, natural gas, produced water or wastes, that can be released into the environment in connection with drilling and production activities, and impose energy efficiency or renewable energy standards on us or users of our products;
|
•
|
limit or prohibit drilling activities on lands located within coastal, wilderness, wetlands, groundwater recharge or endangered species inhabited areas, and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources, and require the dedication of surface acreage for habitat conservation;
|
•
|
establish waste management standards or require remedial measures to limit pollution from former operations, such as pit closure, reclamation and plugging and abandonment of wells or decommissioning of facilities;
|
•
|
impose substantial liabilities for pollution resulting from operations or for preexisting environmental conditions on our current or former properties and operations and other locations where such materials generated by us or our predecessors were released or discharged;
|
•
|
require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting federal, state, and private lands or leases, including preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases.
|
•
|
Clean Air Act (the “CAA”), which governs air emissions;
|
•
|
Clean Water Act (the “CWA”), which governs discharges to and excavations within the waters of the United States;
|
•
|
Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), which imposes liability where hazardous substances have been released into the environment (commonly known as “Superfund”);
|
•
|
The Oil Pollution Act of 1990, which amends and augments the CWA and imposes certain duties and liabilities related to the prevention of oil spills and damages resulting from such spills;
|
•
|
Energy Independence and Security Act of 2007, which prescribes new fuel economy standards and other energy saving measures;
|
•
|
National Environmental Policy Act (“NEPA”), which requires careful evaluation of the environmental impacts of oil and natural gas production activities on federal lands;
|
•
|
Resource Conservation and Recovery Act (“RCRA”), which governs the management of solid waste;
|
•
|
SDWA, which governs the underground injection and disposal of wastewater; and
|
•
|
U.S. Department of Interior regulations, which regulate oil and gas production activities on federal lands and impose liability for pollution cleanup and damages.
|
•
|
worldwide and regional political, regulatory, economic and social conditions impacting the global supply and demand for, and transportation costs of, oil and natural gas, including relaxation of rules against U.S. exports;
|
•
|
military action, war, sanctions and other conflicts;
|
•
|
the price and quantity of foreign imports of oil, particularly in California which imports from foreign countries more than half of the oil it consumes;
|
•
|
the impact of the U.S. dollar exchange rates on oil and expectations about future oil and gas prices;
|
•
|
prevailing prices on local price indexes in the areas in which we operate which are affected by local market conditions and the proximity, capacity, cost and availability of gathering and transportation facilities as well as refining and processing disruptions or bottlenecks;
|
•
|
the level of global exploration, development and production, and resulting inventories, including the significant increase in U.S. activities over the past decade;
|
•
|
actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;
|
•
|
actions of other significant producers;
|
•
|
the cost of exploring for, developing, producing and transporting reserves;
|
•
|
weather conditions and natural disasters;
|
•
|
other irregular events that impact our ability to conduct business or demand for our products, such as the coronavirus outbreak; and
|
•
|
technological advances, conservation efforts and availability of alternative fuels affecting oil and gas consumption.
|
•
|
the volume of hydrocarbons we are able to produce from existing wells;
|
•
|
the prices at which our production is sold and our operating expenses;
|
•
|
the success of our hedging program;
|
•
|
our proved reserves, including our ability to acquire, locate and produce new reserves;
|
•
|
our ability to borrow under the RBL Facility;
|
•
|
and our ability to access the capital markets.
|
•
|
the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements; and
|
•
|
an event materially impacts oil and natural gas prices in the opposite direction of our derivative positions.
|
•
|
the similarity of reservoir performance in other areas to expected performance from our assets;
|
•
|
the quality, quantity and interpretation of available relevant data;
|
•
|
commodity prices (see “—Oil, natural gas and NGL prices are volatile and directly affect our results.”);
|
•
|
production, operating costs, taxes and costs related to GHG regulations;
|
•
|
development costs;
|
•
|
the effects of government regulations; and
|
•
|
future workover and asset retirement costs.
|
•
|
poor production response;
|
•
|
ineffective application of recovery techniques;
|
•
|
increased costs of drilling, completing, stimulating, equipping, operating, maintaining and abandoning wells;
|
•
|
delays or cost overruns caused by equipment failures, accidents, environmental hazards, adverse weather conditions, permitting or construction delays, title disputes, surface access disputes and other matters; and
|
•
|
misinterpretation of geophysical and geological analyses, production data and engineering studies.
|
•
|
delays due to regulatory requirements and procedures, including unavailability or other restrictions limiting permits and limitations on water disposal, emission of GHGs, steam injection and well stimulation, such as California’s recent limitations on cyclic steaming above the fracture gradient;
|
•
|
pressure or irregularities in geological formations;
|
•
|
shortages of or delays in obtaining equipment, qualified personnel or supplies including water for steam used in production or pressure maintenance;
|
•
|
delays in access to production or pipeline transmission facilities; and
|
•
|
power outages imposed by utilities which provide a portion of our electricity needs in order to avoid fire hazards and inspect lines in connection with seasonal strong winds, have begun to occur recently and may impact our operations.
|
•
|
incur or guarantee additional indebtedness or issue certain types of preferred stock;
|
•
|
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;
|
•
|
transfer, sell or dispose of assets;
|
•
|
make investments;
|
•
|
create certain liens securing indebtedness;
|
•
|
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
|
•
|
consolidate, merge or transfer all or substantially all of our assets;
|
•
|
hedge future production or interest rates;
|
•
|
repay or prepay certain indebtedness prior to the due date;
|
•
|
engage in transactions with affiliates; and
|
•
|
engage in certain other transactions without the prior consent of the lenders.
|
•
|
permits stockholders to make investments in competing businesses; and
|
•
|
provides that if one of our directors who is also an employee, officer or director of a stockholder (a “Dual Role Person”), becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.
|
Plan Category
|
|
Number of Securities to be Issued Upon Exercise of Outstanding Options and Rights (#)(1)
|
|
Weighted-Average Exercise Price of Outstanding Options and Rights ($)
|
|
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (#)(3)
|
Equity compensation plans not approved by security holders(2)
|
|
2,348,334
|
|
N/A
|
|
6,954,454
|
(1)
|
The number of securities to be issued upon vesting of unvested restricted stock units ("RSUs") subject to time vesting and performance-based restricted stock units ("PSUs"), assumes maximum achievement of certain market-based performance goals over a specified period of time
|
(2)
|
In connection with the IPO, our Board amended and restated the Company’s First Amended and Restated 2017 Omnibus Incentive Plan, which had amended and restated the Company’s 2017 Omnibus Incentive Plan (the “Prior Plans” and, collectively with the Omnibus Plan, the “Equity Compensation Plans”), which allowed us to grant equity-based compensation awards with respect to up to 10,000,000 shares of common stock (which number includes the number of shares of common stock previously issued pursuant to an award (or made subject to an award that has not expired or been terminated) under the Prior Plans), to employees, consultants and directors of the Company and its affiliates who perform services for the Company. The Omnibus Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents and other types of awards.
|
(3)
|
The number of securities remaining available for future issuances has been reduced by the number of securities to be issued upon settlement of RSUs subject to time vesting and PSUs assuming maximum achievement of certain market-based performance goals over a specified period of time
|
Period
|
|
Total Number of Shares Purchased
|
|
Average Price Paid per Share
|
|
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
|
|
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
|
||||||
October 1 - 31, 2019
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
|
||
November 1 - 30, 2019
|
|
1,252,696
|
|
|
$
|
7.60
|
|
|
1,252,696
|
|
|
|
||
December 1 - 31, 2019
|
|
156,163
|
|
|
$
|
7.98
|
|
|
156,163
|
|
|
|
||
Total
|
|
1,408,859
|
|
|
$
|
7.64
|
|
|
1,408,859
|
|
|
$
|
—
|
|
|
7/26/18
|
|
09/18
|
|
12/18
|
|
03/19
|
|
06/19
|
|
09/19
|
|
12/19
|
||||||||||||||
Berry Corporation (bry)
|
$
|
100.00
|
|
|
$
|
133.73
|
|
|
$
|
67.17
|
|
|
$
|
89.50
|
|
|
$
|
83.16
|
|
|
$
|
74.34
|
|
|
$
|
75.90
|
|
S&P Smallcap 600
|
$
|
100.00
|
|
|
$
|
104.71
|
|
|
$
|
83.66
|
|
|
$
|
93.37
|
|
|
$
|
95.12
|
|
|
$
|
94.93
|
|
|
$
|
102.72
|
|
Dow Jones U.S. Exploration & Production
|
$
|
100.00
|
|
|
$
|
102.81
|
|
|
$
|
71.18
|
|
|
$
|
80.30
|
|
|
$
|
78.12
|
|
|
$
|
72.14
|
|
|
$
|
79.29
|
|
Vanguard Energy ETF
|
$
|
100.00
|
|
|
$
|
99.64
|
|
|
$
|
73.67
|
|
|
$
|
86.02
|
|
|
$
|
82.49
|
|
|
$
|
76.35
|
|
|
$
|
80.50
|
|
(1)
|
The performance graph shall not be deemed “soliciting material” or to be “filed” with the SEC for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended (the "Securities Act") or the Exchange Act except to the extent that we specifically request it be treated as soliciting material or specifically incorporate it by reference.
|
(2)
|
$100 invested on July 26, 2018 in stock or June 30, 2018 in index, including reinvestment of dividends.
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC
(Predecessor)
|
||||||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
|
Year Ended December 31, 2016
|
||||||||||
|
(in thousands, except per share amounts)
|
|||||||||||||||||||
Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues and other
|
$
|
559,405
|
|
|
$
|
586,557
|
|
|
$
|
319,669
|
|
|
|
$
|
92,718
|
|
|
$
|
410,991
|
|
Net income (loss) attributable to common stockholders(1)(4)
|
$
|
43,539
|
|
|
$
|
49,160
|
|
|
$
|
(39,316
|
)
|
|
|
$
|
(502,964
|
)
|
|
$
|
(1,283,196
|
)
|
Net income (loss) per share of common stock
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
0.54
|
|
|
$
|
0.85
|
|
|
$
|
(1.02
|
)
|
|
|
n/a
|
|
|
n/a
|
|
||
Diluted
|
$
|
0.53
|
|
|
$
|
0.85
|
|
|
$
|
(1.02
|
)
|
|
|
n/a
|
|
|
n/a
|
|
||
Dividends per common share
|
$
|
0.48
|
|
|
$
|
0.21
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Weighted-average common stock outstanding(2)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
81,379
|
|
|
57,743
|
|
|
38,644
|
|
|
|
n/a
|
|
|
n/a
|
|
|||||
Diluted(2)
|
81,951
|
|
|
57,932
|
|
|
38,644
|
|
|
|
n/a
|
|
|
n/a
|
|
|||||
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities(3)
|
$
|
241,829
|
|
|
$
|
105,471
|
|
|
$
|
107,399
|
|
|
|
$
|
22,431
|
|
|
$
|
13,197
|
|
Capital expenditures
|
$
|
(223,154
|
)
|
|
$
|
(129,652
|
)
|
|
$
|
(65,479
|
)
|
|
|
$
|
(3,158
|
)
|
|
$
|
(34,796
|
)
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
1,690,198
|
|
|
$
|
1,692,263
|
|
|
$
|
1,546,402
|
|
|
|
$
|
1,561,038
|
|
|
$
|
2,652,050
|
|
Long-term debt, net
|
$
|
394,319
|
|
|
$
|
391,786
|
|
|
$
|
379,000
|
|
|
|
$
|
400,000
|
|
|
$
|
—
|
|
(1)
|
Refer to “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” for discussion regarding factors in comparability, such as, impairment of its Piceance gas properties and income taxes in 2019.
|
(2)
|
The Series A Preferred Stock was not a participating security; therefore, we calculated diluted earnings per share using the “if-converted” method, under which the preferred dividends are added back to the numerator and the Series A Preferred Stock is assumed to be converted at the beginning of the period. No incremental shares of Series A Preferred Stock were included in the diluted EPS calculation for the years ended December 31, 2019 or 2018, as all outstanding shares of our Series A Preferred (the "Series A Preferred Stock") were converted to common shares (the "Series A Preferred Stock Conversion") in connection with the IPO of our common stock in July 2018. No incremental shares of Series A Preferred Stock were included in the diluted earnings per share calculation for the ten months ended December 31, 2017 as their effect was antidilutive under the “if-converted” method. Please see Note 6 for further detail.
|
(3)
|
2018 includes a one-time payment of $127 million in the second quarter to early terminate unsettled derivative contracts. The elective cancellation was effected to realign our hedging pricing with current market rates and move from WTI to Brent underlying.
|
(4)
|
Net Income Attributable to Common Stockholders for year ended December 31, 2019 includes a $51 million non-cash impairment charge for the Piceance gas properties, and $39 million in income tax credits from prior periods.
|
|
Year Ended
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
Brent oil ($/Bbl)
|
$
|
64.16
|
|
|
$
|
71.69
|
|
WTI oil ($/Bbl)
|
$
|
57.03
|
|
|
$
|
64.81
|
|
Kern, Delivered natural gas ($/MMBtu)
|
$
|
3.14
|
|
|
$
|
3.36
|
|
Henry Hub natural gas ($/MMBtu)
|
$
|
2.56
|
|
|
$
|
3.15
|
|
|
Year Ended
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
Average daily production:(1)(3)
|
|
|
|
||||
Oil (MBbl/d)
|
25.3
|
|
|
22.0
|
|
||
Natural Gas (MMcf/d)
|
20.0
|
|
|
26.3
|
|
||
NGLs (MBbl/d)
|
0.4
|
|
|
0.6
|
|
||
Total (MBoe/d)(2)
|
29.0
|
|
|
27.0
|
|
||
Total Production:(3)
|
|
|
|
||||
Oil (MBbl)
|
9,226
|
|
|
8,045
|
|
||
Natural gas (MMcf)
|
7,302
|
|
|
9,589
|
|
||
NGLs (MBbl)
|
151
|
|
|
211
|
|
||
Total (MBoe)(2)
|
10,594
|
|
|
9,855
|
|
||
Weighted-average realized prices:
|
|
|
|
||||
Oil with hedges (Bbl)
|
$
|
63.61
|
|
|
$
|
59.67
|
|
Oil without hedges (Bbl)
|
$
|
58.93
|
|
|
$
|
64.76
|
|
Natural gas (Mcf)
|
$
|
2.66
|
|
|
$
|
2.74
|
|
NGLs (Bbl)
|
$
|
17.02
|
|
|
$
|
26.74
|
|
Average Benchmark prices:
|
|
|
|
||||
Oil (Bbl) – Brent
|
$
|
64.16
|
|
|
$
|
71.69
|
|
Oil (Bbl) – WTI
|
$
|
57.03
|
|
|
$
|
64.81
|
|
Gas (MMBtu) – Kern, Delivered(4)
|
$
|
3.14
|
|
|
$
|
3.36
|
|
Natural gas (MMBtu) – Henry Hub(5)
|
$
|
2.56
|
|
|
$
|
3.15
|
|
(1)
|
Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.
|
(2)
|
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, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per MMBtu respectively, resulting in an oil-to-gas ratio of approximately 4 to 1 on an energy equivalent basis.
|
(3)
|
On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
|
(4)
|
Kern, Delivered Index is the relevant index used for gas purchases in California.
|
(5)
|
Henry Hub is the relevant index used for gas sales in the Rockies.
|
|
Year Ended
|
||||
|
December 31, 2019
|
|
December 31, 2018
|
||
Average daily production (MBoe/d)(1):
|
|
|
|
||
California
|
22.6
|
|
|
19.7
|
|
Utah
|
5.0
|
|
|
4.9
|
|
Colorado
|
1.4
|
|
|
1.7
|
|
East Texas(2)
|
—
|
|
|
0.7
|
|
Total average daily production
|
29.0
|
|
|
27.0
|
|
(1)
|
Production represents volumes sold during the period.
|
(2)
|
On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
|
|
California
(San Joaquin and Ventura basins) |
|
Utah
(Uinta basin) |
|
Colorado
(Piceance basin) |
|||||||||||||||
|
Year Ended December 31, 2019
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2019
|
Year Ended December 31, 2018
|
|
Year Ended December 31, 2019
|
Year Ended December 31, 2018
|
||||||||||||
($ in thousands, unless noted otherwise)
|
|
|
|
|
|
|
|
|
||||||||||||
Oil, natural gas and natural gas liquids sales
|
$
|
498,325
|
|
$
|
471,802
|
|
|
$
|
59,383
|
|
$
|
65,605
|
|
|
$
|
7,740
|
|
$
|
10,657
|
|
Operating income(1)
|
$
|
230,500
|
|
$
|
185,965
|
|
|
$
|
7,624
|
|
$
|
15,066
|
|
|
$
|
(48,955
|
)
|
$
|
6,346
|
|
Depreciation, depletion, and amortization (DD&A)
|
$
|
93,025
|
|
$
|
72,260
|
|
|
$
|
11,754
|
|
$
|
10,420
|
|
|
$
|
1,055
|
|
$
|
646
|
|
Impairment of oil and gas properties
|
$
|
—
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
51,081
|
|
$
|
—
|
|
Average daily production (MBoe/d)
|
22.6
|
|
19.7
|
|
|
5.0
|
|
5.0
|
|
|
1.4
|
|
1.7
|
|
||||||
Production (oil % of total)
|
100
|
%
|
100
|
%
|
|
54
|
%
|
48
|
%
|
|
2
|
%
|
1
|
%
|
||||||
Realized sales prices:
|
|
|
|
|
|
|
|
|
||||||||||||
Oil (per Bbl)
|
$
|
60.51
|
|
$
|
65.64
|
|
|
$
|
45.72
|
|
$
|
57.30
|
|
|
$
|
52.36
|
|
$
|
61.50
|
|
NGLs (per Bbl)
|
$
|
—
|
|
$
|
—
|
|
|
$
|
17.08
|
|
$
|
26.95
|
|
|
$
|
—
|
|
$
|
—
|
|
Gas (per Mcf)
|
$
|
—
|
|
$
|
—
|
|
|
$
|
2.94
|
|
$
|
2.68
|
|
|
$
|
2.26
|
|
$
|
2.75
|
|
Capital expenditures(2)
|
$
|
191,955
|
|
$
|
125,565
|
|
|
$
|
10,229
|
|
$
|
16,738
|
|
|
$
|
603
|
|
$
|
613
|
|
Total proved reserves (MMBoe)
|
122
|
|
106
|
|
|
15
|
|
19
|
|
|
1
|
|
18
|
|
(1)
|
Operating income includes oil, natural gas and NGL sales, marketing revenues, other revenues, and scheduled oil derivative settlements, offset by operating expenses, general and administrative expenses, DD&A, impairment of oil and gas properties, and taxes, other than income taxes.
|
(2)
|
Excludes corporate capital expenditures.
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
$ Change
|
|
% Change
|
|||||||
|
(in thousands)
|
|
|
|||||||||||
Revenues and other:
|
|
|
|
|
|
|
|
|||||||
Oil, natural gas and natural gas liquid sales
|
$
|
565,596
|
|
|
$
|
552,874
|
|
|
$
|
12,722
|
|
|
2
|
%
|
Electricity sales
|
29,397
|
|
|
35,208
|
|
|
(5,811
|
)
|
|
(17
|
)%
|
|||
(Losses) gains on oil derivatives
|
(37,998
|
)
|
|
(4,621
|
)
|
|
(33,377
|
)
|
|
722
|
%
|
|||
Marketing and other revenues
|
2,410
|
|
|
3,096
|
|
|
(686
|
)
|
|
(22
|
)%
|
|||
Total revenues and other
|
$
|
559,405
|
|
|
$
|
586,557
|
|
|
$
|
(27,152
|
)
|
|
(5
|
)%
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
$ Change
|
|
% Change
|
|||||||
|
(in thousands)
|
|
|
|||||||||||
Expenses and other:
|
|
|
|
|
|
|
|
|||||||
Lease operating expenses
|
$
|
216,294
|
|
|
$
|
188,776
|
|
|
$
|
27,518
|
|
|
15
|
%
|
Electricity generation expenses
|
19,490
|
|
|
20,619
|
|
|
(1,129
|
)
|
|
(5
|
)%
|
|||
Transportation expenses
|
8,059
|
|
|
9,860
|
|
|
(1,801
|
)
|
|
(18
|
)%
|
|||
Marketing expenses
|
2,073
|
|
|
2,140
|
|
|
(67
|
)
|
|
(3
|
)%
|
|||
General and administrative expenses
|
62,643
|
|
|
54,026
|
|
|
8,617
|
|
|
16
|
%
|
|||
Depreciation, depletion and amortization
|
106,006
|
|
|
86,271
|
|
|
19,735
|
|
|
23
|
%
|
|||
Impairment of oil and gas properties(6)
|
51,081
|
|
|
—
|
|
|
51,081
|
|
|
100
|
%
|
|||
Taxes, other than income taxes
|
40,645
|
|
|
33,117
|
|
|
7,528
|
|
|
23
|
%
|
|||
Losses (gains) on natural gas derivatives
|
6,957
|
|
|
(6,357
|
)
|
|
13,314
|
|
|
n/a
|
|
|||
Other operating expense (income)
|
4,588
|
|
|
(2,747
|
)
|
|
7,335
|
|
|
(267
|
)%
|
|||
Total expenses and other
|
517,836
|
|
|
385,705
|
|
|
132,131
|
|
|
34
|
%
|
|||
Other income (expenses):
|
|
|
|
|
|
|
|
|||||||
Interest expense
|
(34,234
|
)
|
|
(35,648
|
)
|
|
1,414
|
|
|
(4
|
)%
|
|||
Other, net
|
80
|
|
|
243
|
|
|
(163
|
)
|
|
(67
|
)%
|
|||
Total other income (expenses)
|
(34,154
|
)
|
|
(35,405
|
)
|
|
1,251
|
|
|
(4
|
)%
|
|||
Reorganization items, net
|
(426
|
)
|
|
24,690
|
|
|
(25,116
|
)
|
|
(102
|
)%
|
|||
Income (loss) before income taxes
|
6,989
|
|
|
190,137
|
|
|
(183,148
|
)
|
|
(96
|
)%
|
|||
Income tax expense (benefit)
|
(36,550
|
)
|
|
43,035
|
|
|
(79,585
|
)
|
|
(185
|
)%
|
|||
Net (loss) income
|
43,539
|
|
|
147,102
|
|
|
(103,563
|
)
|
|
(70
|
)%
|
|||
Series A Preferred Stock dividends and conversion to common stock
|
—
|
|
|
(97,942
|
)
|
|
97,942
|
|
|
(100
|
)%
|
|||
Net (loss) income attributable to common stockholders
|
$
|
43,539
|
|
|
$
|
49,160
|
|
|
$
|
(5,621
|
)
|
|
(11
|
)%
|
Adjusted EBITDA(7)
|
$
|
302,184
|
|
|
$
|
257,924
|
|
|
$
|
44,260
|
|
|
17
|
%
|
Adjusted Net Income (Loss)(7)
|
$
|
110,228
|
|
|
$
|
100,001
|
|
|
$
|
10,227
|
|
|
10
|
%
|
|
|
|
|
|
|
|
|
Expenses per Boe:(1)
|
|
|
|
|
|
|
|
|||||||
Lease operating expenses
|
$
|
20.42
|
|
|
$
|
19.16
|
|
|
$
|
1.26
|
|
|
7
|
%
|
Electricity generation expenses
|
1.84
|
|
|
2.09
|
|
|
(0.25
|
)
|
|
(12
|
)%
|
|||
Electricity sales
|
(2.77
|
)
|
|
(3.57
|
)
|
|
0.80
|
|
|
(22
|
)%
|
|||
Transportation expenses
|
0.76
|
|
|
1.00
|
|
|
(0.24
|
)
|
|
(24
|
)%
|
|||
Transportation sales
|
(0.03
|
)
|
|
(0.08
|
)
|
|
0.05
|
|
|
(63
|
)%
|
|||
Marketing expenses
|
0.20
|
|
|
0.22
|
|
|
(0.02
|
)
|
|
(9
|
)%
|
|||
Marketing revenues
|
(0.20
|
)
|
|
(0.24
|
)
|
|
0.04
|
|
|
(17
|
)%
|
|||
Gas purchase derivatives settlement (gains) losses
|
0.10
|
|
|
(0.24
|
)
|
|
0.34
|
|
|
(142
|
)%
|
|||
Total operating expenses
|
$
|
20.32
|
|
|
$
|
18.33
|
|
|
$
|
1.99
|
|
|
11
|
%
|
Total unhedged operating expenses(2)
|
$
|
20.22
|
|
|
$
|
18.57
|
|
|
$
|
1.65
|
|
|
9
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total non-energy operating expenses(3)
|
$
|
14.80
|
|
|
$
|
13.80
|
|
|
$
|
1.00
|
|
|
7
|
%
|
Total energy operating expenses(4)
|
$
|
5.51
|
|
|
$
|
4.53
|
|
|
$
|
0.98
|
|
|
22
|
%
|
|
|
|
|
|
|
|
|
|||||||
General and administrative expenses(5)
|
$
|
5.91
|
|
|
$
|
5.48
|
|
|
$
|
0.43
|
|
|
8
|
%
|
Depreciation, depletion and amortization
|
$
|
10.01
|
|
|
$
|
8.75
|
|
|
$
|
1.26
|
|
|
14
|
%
|
Taxes, other than income taxes
|
$
|
3.84
|
|
|
$
|
3.36
|
|
|
$
|
0.48
|
|
|
14
|
%
|
(1)
|
We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses also include the effect of derivative settlements (received or paid) for gas purchases.
|
(2)
|
Total unhedged operating expenses equals total operating expenses less the derivatives settlements paid for gas purchases.
|
(3)
|
Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivatives settlement (gains) losses.
|
(4)
|
Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.
|
(5)
|
Includes restructuring and other non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.08 per Boe and $1.36 per Boe for the year ended December 31, 2019 and December 31, 2018, respectively.
|
(6)
|
For the year ended December 31, 2019, we recorded an impairment charge of $51 million for the Piceance gas properties in Colorado.
|
(7)
|
Adjusted EBITDA and Adjusted Net Income (Loss) are financial measures that are not calculated in accordance with GAAP. For definitions and a reconciliation to the Net Cash Provided by Operating Activities and Net Income (Loss), please see “Item 7 — Non-GAAP Financial Measures”
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
$ Change
|
|
% Change
|
|||||||
|
(per Boe)
|
|
|
|
||||||||||
Severance taxes
|
$
|
0.63
|
|
|
$
|
0.95
|
|
|
$
|
(0.32
|
)
|
|
(34
|
)%
|
Ad valorem taxes
|
1.38
|
|
|
1.38
|
|
|
0.00
|
|
|
0
|
%
|
|||
Greenhouse gas allowances
|
1.83
|
|
|
1.03
|
|
|
0.80
|
|
|
78
|
%
|
|||
Total taxes other than income taxes
|
$
|
3.84
|
|
|
$
|
3.36
|
|
|
$
|
0.48
|
|
|
14
|
%
|
|
Q1 2020
|
|
Q2 2020
|
|
Q3 2020
|
|
Q4 2020
|
|
FY 2021
|
||||||||||
Fixed Price Oil Swaps (Brent):
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged volume (MBbls)
|
1,729
|
|
|
1,456
|
|
|
1,472
|
|
|
1,472
|
|
|
730
|
|
|||||
Weighted average price ($/Bbl)
|
$
|
63.92
|
|
|
$
|
64.30
|
|
|
$
|
64.21
|
|
|
$
|
64.21
|
|
|
$
|
58.50
|
|
Fixed Price Oil Swaps (WTI):
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged volume (MBbls)
|
91
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Weighted average price ($/Bbl)
|
$
|
61.75
|
|
|
$
|
61.75
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Fixed Price Gas Purchase Swaps (Kern, Delivered):
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged volume (MMBtu)
|
5,005,000
|
|
|
5,005,000
|
|
|
5,060,000
|
|
|
2,315,000
|
|
|
900,000
|
|
|||||
Weighted average price ($/MMBtu)
|
$
|
2.89
|
|
|
$
|
2.89
|
|
|
$
|
2.89
|
|
|
$
|
2.79
|
|
|
$
|
2.50
|
|
Fixed Price Gas Purchase Swaps (SoCal Citygate):
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged volume (MMBtu)
|
455,000
|
|
|
455,000
|
|
|
460,000
|
|
|
155,000
|
|
|
—
|
|
|||||
Weighted average price ($/MMBtu)
|
$
|
3.80
|
|
|
$
|
3.80
|
|
|
$
|
3.80
|
|
|
$
|
3.80
|
|
|
$
|
—
|
|
|
Year Ended
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
Crude Oil (per Bbl):
|
|
|
|
||||
Realized sales price, before the effects of derivative settlements
|
$
|
58.93
|
|
|
$
|
64.76
|
|
Effects of derivative settlements
|
$
|
4.69
|
|
|
$
|
(5.09
|
)
|
Natural Gas (per MMBtu):
|
|
|
|
||||
Purchase price, before the effects of derivative settlements
|
$
|
3.18
|
|
|
$
|
3.27
|
|
Effects of derivative settlements
|
$
|
0.04
|
|
|
$
|
(0.10
|
)
|
|
Year Ended
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Net cash:
|
|
|
|
||||
Provided by operating activities(1)
|
$
|
241,829
|
|
|
$
|
105,471
|
|
Used in investing activities
|
(225,025
|
)
|
|
(121,440
|
)
|
||
(Used in) provided by financing activities
|
(85,484
|
)
|
|
15,911
|
|
||
Net decrease in cash, cash equivalents and restricted cash
|
$
|
(68,680
|
)
|
|
$
|
(58
|
)
|
(1)
|
The amounts provided by operating activities in 2018 were negatively impacted by a one-time $127 million payment in May 2018 for early termination on derivatives.
|
|
Year Ended
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Capital expenditures (1)
|
|
|
|
||||
Development of oil and natural gas properties
|
$
|
(219,176
|
)
|
|
$
|
(94,225
|
)
|
Changes in capital investment accruals
|
12,814
|
|
|
(20,371
|
)
|
||
Purchase of other property and equipment
|
(16,792
|
)
|
|
(15,056
|
)
|
||
Acquisition of properties and equipment
|
(2,840
|
)
|
|
—
|
|
||
Proceeds from sale of properties and equipment and other
|
969
|
|
|
8,212
|
|
||
Cash used in investing activities:
|
$
|
(225,025
|
)
|
|
$
|
(121,440
|
)
|
(1)
|
Based on actual cash payments rather than accrual.
|
|
|
Payments Due
|
||||||||||||||||||
|
|
Total
|
|
2020
|
|
2021-2022
|
|
2023-2024
|
|
Thereafter
|
||||||||||
|
|
(in thousands)
|
||||||||||||||||||
Debt obligations:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
RBL Facility
|
|
$
|
1,850
|
|
|
$
|
—
|
|
|
$
|
1,850
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2026 Notes
|
|
400,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
400,000
|
|
|||||
Interest(1)
|
|
171,529
|
|
|
28,000
|
|
|
56,000
|
|
|
56,000
|
|
|
31,529
|
|
|||||
Other:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Asset retirement obligations(2)
|
|
149,227
|
|
|
21,434
|
|
|
—
|
|
|
—
|
|
|
127,793
|
|
|||||
Off-Balance Sheet arrangements:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Processing and transportation contracts(3)
|
|
13,462
|
|
|
7,136
|
|
|
5,265
|
|
|
1,061
|
|
|
—
|
|
|||||
Operating lease obligations
|
|
11,969
|
|
|
1,723
|
|
|
3,471
|
|
|
3,067
|
|
|
3,708
|
|
|||||
Other(4)
|
|
6,000
|
|
|
6,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total contractual obligations
|
|
$
|
754,037
|
|
|
$
|
64,293
|
|
|
$
|
66,586
|
|
|
$
|
60,128
|
|
|
$
|
563,030
|
|
(1)
|
Represents interest on the 2026 Notes computed at 7.0% through contractual maturity in 2026.
|
(2)
|
Represents the estimated future asset retirement obligations on a discounted basis. We do not show the long-term asset retirement obligations by year as we are not able to precisely predict the timing of these amounts. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to revisions based on numerous factors, including the rate of inflation, changing technology, and changes to federal, state and local laws and regulations. See Note 1 in the Notes to Consolidated Financial Statements in Part II—Item 8. Financial Statements and Supplementary Data for more information.
|
(3)
|
Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure transportation of our natural gas production to market as well as pipeline and processing capacity.
|
(4)
|
We have certain commitments under contracts, including purchase commitments for goods and services. We previously had an obligation to a counterparty in connection with our Piceance assets to either build a road or secure a license for alternative access, in lieu of paying a $6 million penalty. As of December 31, 2019, we fulfilled the obligation by delivering the access license pursuant to the agreement. The counterparty has since filed a claim challenging the sufficiency of such access.
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
68,680
|
|
Accounts receivable, net
|
$
|
71,867
|
|
|
$
|
57,379
|
|
Derivative instruments - current and long-term
|
$
|
9,691
|
|
|
$
|
91,885
|
|
Other current assets
|
$
|
19,399
|
|
|
$
|
14,367
|
|
Property, plant & equipment, net
|
$
|
1,576,267
|
|
|
$
|
1,442,708
|
|
Other non-current assets
|
$
|
12,974
|
|
|
$
|
17,244
|
|
Accounts payable and accrued liabilities
|
$
|
151,811
|
|
|
$
|
144,118
|
|
Derivative instruments - current and long-term
|
$
|
4,958
|
|
|
$
|
—
|
|
Long-term debt
|
$
|
394,319
|
|
|
$
|
391,786
|
|
Asset retirement obligation
|
$
|
124,019
|
|
|
$
|
89,176
|
|
Other non-current liabilities
|
$
|
33,586
|
|
|
$
|
14,902
|
|
Equity
|
$
|
972,448
|
|
|
$
|
1,006,446
|
|
|
Year Ended
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Adjusted EBITDA reconciliation to net income (loss):
|
|
|
|
||||
Net (loss) income
|
$
|
43,539
|
|
|
$
|
147,102
|
|
Add (Subtract):
|
|
|
|
||||
Interest expense
|
34,234
|
|
|
35,648
|
|
||
Income tax expense (benefit)
|
(36,550
|
)
|
|
43,035
|
|
||
Depreciation, depletion, and amortization
|
106,006
|
|
|
86,271
|
|
||
Impairment of oil and gas properties
|
51,081
|
|
|
—
|
|
||
Derivative losses (gains)
|
44,955
|
|
|
(1,735
|
)
|
||
Net cash received (paid) for scheduled derivative settlements(1)
|
42,197
|
|
|
(38,482
|
)
|
||
Other operating expenses (income)
|
4,588
|
|
|
(2,747
|
)
|
||
Stock compensation expense
|
8,647
|
|
|
6,750
|
|
||
Restructuring and other non-recurring costs
|
3,061
|
|
|
6,773
|
|
||
Reorganization items, net
|
426
|
|
|
(24,690
|
)
|
||
Adjusted EBITDA
|
$
|
302,184
|
|
|
$
|
257,924
|
|
(1)
|
Net cash received (paid) for scheduled derivative settlements does not include the $127 million in cash paid for early terminated derivatives in 2018.
|
|
Year Ended
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Adjusted EBITDA and Levered Free Cash Flow reconciliation to net cash provided by (used in) operating activities:
|
|||||||
Net cash provided by operating activities
|
$
|
241,829
|
|
|
$
|
105,471
|
|
Add (Subtract):
|
|
|
|
||||
Cash interest payments
|
30,720
|
|
|
19,761
|
|
||
Cash income tax refunds
|
(2
|
)
|
|
(1,901
|
)
|
||
Cash reorganization item payments
|
—
|
|
|
832
|
|
||
Restructuring and other non-recurring costs
|
3,061
|
|
|
6,773
|
|
||
Derivative early termination payment
|
—
|
|
|
126,949
|
|
||
Other changes in operating assets and liabilities
|
26,576
|
|
|
39
|
|
||
Adjusted EBITDA
|
$
|
302,184
|
|
|
$
|
257,924
|
|
Subtract:
|
|
|
|
||||
Capital expenditures - accrual basis
|
(211,095
|
)
|
|
(147,831
|
)
|
||
Interest expense
|
(34,234
|
)
|
|
(35,648
|
)
|
||
Cash dividends declared(1)
|
(39,053
|
)
|
|
(28,658
|
)
|
||
Levered Free Cash Flow(2)
|
$
|
17,802
|
|
|
$
|
45,787
|
|
(1)
|
Cash dividends declared in 2018 include $11 million of dividends for Series A Preferred Stock for the first two quarters of 2018 and $17 million of dividends for common stock. In connection with our IPO in July 2018, all of our outstanding Series A Preferred Stock was automatically converted into common stock. Common stock dividends were $0.09 per share for the third quarter of 2018, which was pro-rated from the date of our IPO through September 30, 2018, and $0.12 per share for the fourth quarter of 2018 and each quarter in 2019.
|
(2)
|
Levered Free Cash Flow includes cash received for scheduled derivative settlements of $42 million for the year ended December 31, 2019, and cash paid for scheduled derivative settlements $38 million for the year ended December 31, 2018.
|
(1)
|
Excludes prior year income tax credits from the total additions (subtractions), net line item and the tax effect the prior tax credits have on the current year effective tax rate.
|
|
(in thousands)
|
||
Liabilities subject to compromise
|
$
|
1,000,336
|
|
Pre-petition debt not classified as subject to compromise
|
891,259
|
|
|
Post-petition liabilities
|
245,702
|
|
|
Total post-petition liabilities and allowed claims
|
2,137,297
|
|
|
Reorganization value of assets immediately prior to implementation of the Plan
|
(1,722,585
|
)
|
|
Excess post-petition liabilities and allowed claims
|
$
|
414,712
|
|
•
|
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, meet our working capital requirements or fund planned investments;
|
•
|
price and availability of natural gas;
|
•
|
our ability to use derivative instruments to manage commodity price risk;
|
•
|
availability or timing of, or conditions imposed on, permits and approvals;
|
•
|
our ability to meet our planned drilling schedule, including due to our ability to obtain permits, and to successfully drill wells that produce oil and natural gas in commercially viable quantities;
|
•
|
the impact of current laws and regulations, and of pending or future legislative and regulatory changes and other government activities, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products;
|
•
|
concerns about climate change and other air quality issues;
|
•
|
uncertainties associated with estimating proved reserves and related future cash flows;
|
•
|
our ability to replace our reserves through exploration and development activities;
|
•
|
lower–than–expected production, reserves or resources from development projects or higher–than–expected decline rates;
|
•
|
our ability to obtain timely and available drilling and completion equipment and crew availability and access to necessary resources for drilling, completing and operating wells
|
•
|
changes in tax laws;
|
•
|
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;
|
•
|
impact of derivatives legislation affecting our ability to hedge;
|
•
|
ineffectiveness of internal controls;
|
•
|
catastrophic events;
|
•
|
litigation;
|
•
|
our ability to retain key members of our senior management and key technical employees; and
|
•
|
information technology failures or cyber attacks.
|
|
Page
|
|
Berry Corp.
(Successor) |
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands, except share amounts)
|
||||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
68,680
|
|
Accounts receivable, net of allowance for doubtful accounts of $1,103 at December 31, 2019 and $950 at December 31, 2018
|
71,867
|
|
|
57,379
|
|
||
Derivative instruments
|
9,166
|
|
|
88,596
|
|
||
Other current assets
|
19,399
|
|
|
14,367
|
|
||
Total current assets
|
100,432
|
|
|
229,022
|
|
||
Non-current assets:
|
|
|
|
||||
Oil and natural gas properties
|
1,675,717
|
|
|
1,461,993
|
|
||
Accumulated depletion and amortization
|
(209,105
|
)
|
|
(123,217
|
)
|
||
Total oil and natural gas properties, net
|
1,466,612
|
|
|
1,338,776
|
|
||
Other property and equipment
|
135,117
|
|
|
119,710
|
|
||
Accumulated depreciation
|
(25,462
|
)
|
|
(15,778
|
)
|
||
Total other property and equipment, net
|
109,655
|
|
|
103,932
|
|
||
Derivative instruments
|
525
|
|
|
3,289
|
|
||
Other non-current assets
|
12,974
|
|
|
17,244
|
|
||
Total assets
|
$
|
1,690,198
|
|
|
$
|
1,692,263
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and accrued expenses
|
$
|
151,811
|
|
|
$
|
144,118
|
|
Derivative instruments
|
4,817
|
|
|
—
|
|
||
Total current liabilities
|
156,628
|
|
|
144,118
|
|
||
Non-current liabilities:
|
|
|
|
||||
Long term debt
|
394,319
|
|
|
391,786
|
|
||
Derivative instruments
|
141
|
|
|
—
|
|
||
Deferred income taxes
|
9,057
|
|
|
45,835
|
|
||
Asset retirement obligation
|
124,019
|
|
|
89,176
|
|
||
Other non-current liabilities
|
33,586
|
|
|
14,902
|
|
||
Commitments and Contingencies - Note 5
|
|
|
|
||||
Equity:
|
|
|
|
||||
Common stock ($.001 par value; 750,000,000 shares authorized; 84,655,222 and 81,651,098 shares issued; and 79,542,976 and 81,202,437 shares outstanding, at December 31, 2019 and December 31, 2018, respectively)
|
85
|
|
|
82
|
|
||
Additional paid-in capital
|
901,830
|
|
|
914,540
|
|
||
Treasury stock, at cost (5,112,246 shares at December 31, 2019 and 448,661 December 31, 2018)
|
(49,995
|
)
|
|
(24,218
|
)
|
||
Retained earnings
|
120,528
|
|
|
116,042
|
|
||
Total equity
|
972,448
|
|
|
1,006,446
|
|
||
Total liabilities and equity
|
$
|
1,690,198
|
|
|
$
|
1,692,263
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
|
(in thousands, except per share amounts)
|
|||||||||||||||
Revenues and other:
|
|
|
|
|
|
|
|
|
||||||||
Oil, natural gas and natural gas liquid sales
|
$
|
565,596
|
|
|
$
|
552,874
|
|
|
$
|
357,928
|
|
|
|
$
|
74,120
|
|
Electricity sales
|
29,397
|
|
|
35,208
|
|
|
21,972
|
|
|
|
3,655
|
|
||||
(Losses) gains on oil derivatives
|
(37,998
|
)
|
|
(4,621
|
)
|
|
(66,900
|
)
|
|
|
12,886
|
|
||||
Marketing revenues
|
2,094
|
|
|
2,322
|
|
|
2,694
|
|
|
|
633
|
|
||||
Other revenues
|
316
|
|
|
774
|
|
|
3,975
|
|
|
|
1,424
|
|
||||
Total revenues and other
|
559,405
|
|
|
586,557
|
|
|
319,669
|
|
|
|
92,718
|
|
||||
Expenses and other:
|
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
216,294
|
|
|
188,776
|
|
|
149,599
|
|
|
|
28,238
|
|
||||
Electricity generation expenses
|
19,490
|
|
|
20,619
|
|
|
14,894
|
|
|
|
3,197
|
|
||||
Transportation expenses
|
8,059
|
|
|
9,860
|
|
|
19,238
|
|
|
|
6,194
|
|
||||
Marketing expenses
|
2,073
|
|
|
2,140
|
|
|
2,320
|
|
|
|
653
|
|
||||
General and administrative expenses
|
62,643
|
|
|
54,026
|
|
|
56,009
|
|
|
|
7,964
|
|
||||
Depreciation, depletion and amortization
|
106,006
|
|
|
86,271
|
|
|
68,478
|
|
|
|
28,149
|
|
||||
Impairment of oil and gas properties
|
51,081
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Taxes, other than income taxes
|
40,645
|
|
|
33,117
|
|
|
34,211
|
|
|
|
5,212
|
|
||||
Losses (gains) on natural gas derivatives
|
6,957
|
|
|
(6,357
|
)
|
|
—
|
|
|
|
—
|
|
||||
Other operating expense (income)
|
4,588
|
|
|
(2,747
|
)
|
|
(22,930
|
)
|
|
|
(183
|
)
|
||||
Total expenses and other
|
517,836
|
|
|
385,705
|
|
|
321,819
|
|
|
|
79,424
|
|
||||
Other income (expenses):
|
|
|
|
|
|
|
|
|
||||||||
Interest expense
|
(34,234
|
)
|
|
(35,648
|
)
|
|
(18,454
|
)
|
|
|
(8,245
|
)
|
||||
Other, net
|
80
|
|
|
243
|
|
|
4,071
|
|
|
|
(63
|
)
|
||||
Total other income (expenses)
|
(34,154
|
)
|
|
(35,405
|
)
|
|
(14,383
|
)
|
|
|
(8,308
|
)
|
||||
Reorganization items, net
|
(426
|
)
|
|
24,690
|
|
|
(1,732
|
)
|
|
|
(507,720
|
)
|
||||
Income (loss) before income taxes
|
6,989
|
|
|
190,137
|
|
|
(18,265
|
)
|
|
|
(502,734
|
)
|
||||
Income tax expense (benefit)
|
(36,550
|
)
|
|
43,035
|
|
|
2,803
|
|
|
|
230
|
|
||||
Net (loss) income
|
43,539
|
|
|
147,102
|
|
|
(21,068
|
)
|
|
|
$
|
(502,964
|
)
|
|||
Series A Preferred Stock dividends and conversion to common stock
|
—
|
|
|
(97,942
|
)
|
|
(18,248
|
)
|
|
|
n/a
|
|
||||
Net (loss) income attributable to common stockholders
|
$
|
43,539
|
|
|
$
|
49,160
|
|
|
$
|
(39,316
|
)
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net (loss) income per share attributable to common stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic
|
$
|
0.54
|
|
|
$
|
0.85
|
|
|
$
|
(1.02
|
)
|
|
|
n/a
|
|
|
Diluted
|
$
|
0.53
|
|
|
$
|
0.85
|
|
|
(1.02
|
)
|
|
|
n/a
|
|
|
Berry LLC (Predecessor)
|
||||||||||
|
Member’s Capital
|
|
Retained Earnings (Accumulated Deficit)
|
|
Total Member’s Equity
|
||||||
|
(in thousands)
|
||||||||||
December 31, 2016
|
$
|
2,798,713
|
|
|
$
|
(2,295,750
|
)
|
|
$
|
502,963
|
|
Net loss
|
—
|
|
|
(502,964
|
)
|
|
(502,964
|
)
|
|||
Other
|
1
|
|
|
—
|
|
|
1
|
|
|||
Balance before cancellation of Predecessor Equity
|
2,798,714
|
|
|
(2,798,714
|
)
|
|
—
|
|
|||
Cancellation of Predecessor Equity
|
(2,798,714
|
)
|
|
2,798,714
|
|
|
—
|
|
|||
Predecessor February 28, 2017
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Berry Corp. (Successor)
|
||||||||||||||||||||||
|
Series A Preferred Stock
|
|
Common Stock
|
|
Additional Paid-in Capital
|
|
Treasury Stock
|
|
Retained Earnings (Accumulated Deficit)
|
|
Total Equity
|
||||||||||||
|
(in thousands)
|
||||||||||||||||||||||
Issuance of Series A convertible preferred stock
|
$
|
335,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
335,000
|
|
Issuance of Common Stock
|
—
|
|
|
33
|
|
|
543,494
|
|
|
—
|
|
|
—
|
|
|
543,527
|
|
||||||
Successor February 28, 2017
|
335,000
|
|
|
33
|
|
|
543,494
|
|
|
—
|
|
|
—
|
|
|
878,527
|
|
||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21,068
|
)
|
|
(21,068
|
)
|
||||||
Stock based compensation
|
—
|
|
|
—
|
|
|
1,851
|
|
|
—
|
|
|
—
|
|
|
1,851
|
|
||||||
December 31, 2017
|
335,000
|
|
|
33
|
|
|
545,345
|
|
|
—
|
|
|
(21,068
|
)
|
|
859,310
|
|
||||||
Cash dividends declared on Series A Preferred Stock, $0.308/share
|
—
|
|
|
—
|
|
|
(11,301
|
)
|
|
—
|
|
|
—
|
|
|
(11,301
|
)
|
||||||
Conversion of Series A Preferred Stock into common stock
|
(335,000
|
)
|
|
40
|
|
|
334,960
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Cash payment to Series A Preferred Stockholders
|
—
|
|
|
—
|
|
|
(60,273
|
)
|
|
—
|
|
|
—
|
|
|
(60,273
|
)
|
||||||
Issuance of common stock in initial public offering
|
—
|
|
|
10
|
|
|
133,795
|
|
|
—
|
|
|
—
|
|
|
133,805
|
|
||||||
Repurchase of common stock
|
—
|
|
|
(2
|
)
|
|
(23,710
|
)
|
|
—
|
|
|
—
|
|
|
(23,712
|
)
|
||||||
Shares withheld for payment of taxes on equity awards
|
—
|
|
|
1
|
|
|
(3,700
|
)
|
|
—
|
|
|
—
|
|
|
(3,699
|
)
|
||||||
Stock based compensation
|
—
|
|
|
—
|
|
|
6,789
|
|
|
—
|
|
|
—
|
|
|
6,789
|
|
||||||
Purchase of rights to common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(20,265
|
)
|
|
—
|
|
|
(20,265
|
)
|
||||||
Purchase of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,953
|
)
|
|
—
|
|
|
(3,953
|
)
|
||||||
Dividends declared on common stock, $0.21/share
|
—
|
|
|
—
|
|
|
(7,365
|
)
|
|
—
|
|
|
(9,992
|
)
|
|
(17,357
|
)
|
||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
147,102
|
|
|
147,102
|
|
||||||
December 31, 2018
|
—
|
|
|
82
|
|
|
914,540
|
|
|
(24,218
|
)
|
|
116,042
|
|
|
1,006,446
|
|
||||||
Shares withheld for payment of taxes on equity awards
|
—
|
|
|
—
|
|
|
(1,268
|
)
|
|
—
|
|
|
—
|
|
|
(1,268
|
)
|
||||||
Stock based compensation
|
—
|
|
|
—
|
|
|
8,826
|
|
|
—
|
|
|
—
|
|
|
8,826
|
|
||||||
Purchase of rights to common stock
|
—
|
|
|
—
|
|
|
(20,265
|
)
|
|
20,265
|
|
|
—
|
|
|
—
|
|
||||||
Purchase of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(46,042
|
)
|
|
—
|
|
|
(46,042
|
)
|
||||||
Common stock issued to settle unsecured claims
|
—
|
|
|
3
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Dividends declared on common stock, $0.48/share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39,053
|
)
|
|
(39,053
|
)
|
||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,539
|
|
|
43,539
|
|
||||||
December 31, 2019
|
$
|
—
|
|
|
$
|
85
|
|
|
$
|
901,830
|
|
|
$
|
(49,995
|
)
|
|
$
|
120,528
|
|
|
$
|
972,448
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
|
(in thousands)
|
|||||||||||||||
Cash flow from operating activities:
|
|
|
|
|
|
|
|
|
||||||||
Net (loss) income
|
$
|
43,539
|
|
|
$
|
147,102
|
|
|
$
|
(21,068
|
)
|
|
|
$
|
(502,964
|
)
|
Adjustments to reconcile net (income) loss to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Depreciation, depletion and amortization
|
106,006
|
|
|
86,271
|
|
|
68,478
|
|
|
|
28,149
|
|
||||
Amortization of debt issuance costs
|
5,059
|
|
|
5,430
|
|
|
1,988
|
|
|
|
416
|
|
||||
Impairment of oil and gas properties
|
51,081
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Stock-based compensation expense
|
8,647
|
|
|
6,750
|
|
|
1,851
|
|
|
|
—
|
|
||||
Deferred income taxes
|
(36,778
|
)
|
|
43,946
|
|
|
1,888
|
|
|
|
9
|
|
||||
Increase (decrease) in allowance for doubtful accounts
|
153
|
|
|
(20
|
)
|
|
970
|
|
|
|
—
|
|
||||
Other operating expenses (income)
|
5,518
|
|
|
(2,747
|
)
|
|
(22,930
|
)
|
|
|
(25
|
)
|
||||
Reorganization expenses, net (non-cash)
|
—
|
|
|
(25,523
|
)
|
|
—
|
|
|
|
501,872
|
|
||||
Derivatives activities:
|
|
|
|
|
|
|
|
|
|
|
||||||
Total losses (gains)
|
44,955
|
|
|
(1,735
|
)
|
|
66,900
|
|
|
|
(12,886
|
)
|
||||
Cash settlements on derivatives
|
42,197
|
|
|
(38,482
|
)
|
|
3,068
|
|
|
|
534
|
|
||||
Cash payments on early-terminated derivatives
|
—
|
|
|
(126,949
|
)
|
|
—
|
|
|
|
—
|
|
||||
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|||||
(Increase) decrease in accounts receivable
|
(14,597
|
)
|
|
(1,683
|
)
|
|
(7,022
|
)
|
|
|
(9,152
|
)
|
||||
(Increase) decrease in other assets
|
(5,136
|
)
|
|
(819
|
)
|
|
(13,175
|
)
|
|
|
(2,842
|
)
|
||||
Increase (decrease) in accounts payable and accrued expenses
|
(917
|
)
|
|
19,526
|
|
|
6,619
|
|
|
|
18,330
|
|
||||
(Decrease) increase in other liabilities
|
(7,898
|
)
|
|
(5,596
|
)
|
|
19,832
|
|
|
|
990
|
|
||||
Net cash provided by operating activities
|
241,829
|
|
|
105,471
|
|
|
107,399
|
|
|
|
22,431
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Cash flow from investing activities:
|
|
|
|
|
|
|
|
|
||||||||
Capital expenditures:
|
|
|
|
|
|
|
|
|
||||||||
Development of oil and natural gas properties
|
(219,176
|
)
|
|
(94,225
|
)
|
|
(50,229
|
)
|
|
|
(247
|
)
|
||||
Changes in capital investment accruals
|
12,814
|
|
|
(20,371
|
)
|
|
(2,483
|
)
|
|
|
(2,249
|
)
|
||||
Purchases of other property and equipment
|
(16,792
|
)
|
|
(15,056
|
)
|
|
(12,767
|
)
|
|
|
(662
|
)
|
||||
Acquisition of properties and equipment
|
(2,840
|
)
|
|
—
|
|
|
(249,338
|
)
|
|
|
—
|
|
||||
Proceeds from sale of property and equipment and other
|
969
|
|
|
8,212
|
|
|
234,292
|
|
|
|
25
|
|
||||
Net cash (used in) investing activities
|
(225,025
|
)
|
|
(121,440
|
)
|
|
(80,525
|
)
|
|
|
(3,133
|
)
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Cash flow from financing activities:
|
|
|
|
|
|
|
|
|
||||||||
Borrowings under RBL credit facility
|
355,132
|
|
|
203,510
|
|
|
402,285
|
|
|
|
—
|
|
||||
Repayments on RBL credit facility
|
(353,282
|
)
|
|
(582,510
|
)
|
|
(23,285
|
)
|
|
|
—
|
|
||||
Dividends paid on common stock
|
(39,157
|
)
|
|
(7,365
|
)
|
|
—
|
|
|
|
—
|
|
||||
Purchase of treasury stock
|
(46,909
|
)
|
|
(23,351
|
)
|
|
—
|
|
|
|
—
|
|
||||
Shares withheld for payment of taxes on equity awards and other
|
(1,268
|
)
|
|
(3,699
|
)
|
|
—
|
|
|
|
—
|
|
||||
Issuance of 2026 Senior Unsecured Notes
|
—
|
|
|
400,000
|
|
|
—
|
|
|
|
—
|
|
||||
Debt issuance costs
|
—
|
|
|
(9,193
|
)
|
|
(22,170
|
)
|
|
|
—
|
|
||||
IPO proceeds net of issuance costs
|
—
|
|
|
133,805
|
|
|
—
|
|
|
|
—
|
|
||||
Repurchase of common stock
|
—
|
|
|
(23,712
|
)
|
|
—
|
|
|
|
—
|
|
||||
Payment to preferred stockholders in conversion
|
—
|
|
|
(60,273
|
)
|
|
—
|
|
|
|
—
|
|
||||
Dividends paid on Series A Preferred Stock
|
—
|
|
|
(11,301
|
)
|
|
—
|
|
|
|
—
|
|
||||
Borrowings on emergence credit facility
|
—
|
|
|
—
|
|
|
51,000
|
|
|
|
—
|
|
||||
Repayments on emergence credit facility
|
—
|
|
|
—
|
|
|
(451,000
|
)
|
|
|
—
|
|
||||
Proceeds from sale of Series A Preferred Stock
|
—
|
|
|
—
|
|
|
—
|
|
|
|
335,000
|
|
||||
Repayments on pre-emergence credit facility
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(497,668
|
)
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
|
(in thousands)
|
|||||||||||||||
Net cash (used in) provided by financing activities
|
(85,484
|
)
|
|
15,911
|
|
|
(43,170
|
)
|
|
|
(162,668
|
)
|
||||
Net decrease in cash and cash equivalents
|
(68,680
|
)
|
|
(58
|
)
|
|
(16,296
|
)
|
|
|
(143,370
|
)
|
||||
Cash, cash equivalents and restricted cash:
|
|
|
|
|
|
|
|
|
||||||||
Beginning
|
68,680
|
|
|
68,738
|
|
|
85,034
|
|
|
|
228,404
|
|
||||
Ending
|
$
|
—
|
|
|
$
|
68,680
|
|
|
$
|
68,738
|
|
|
|
$
|
85,034
|
|
|
Berry Corp.
(Successor) |
||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||||
|
(in thousands)
|
||||||
Beginning balance
|
$
|
95,548
|
|
|
$
|
97,422
|
|
Liabilities incurred
|
11,534
|
|
|
4,901
|
|
||
Settlements and payments
|
(22,036
|
)
|
|
(3,555
|
)
|
||
Accretion expense
|
7,570
|
|
|
6,258
|
|
||
Reduction due to property sales
|
—
|
|
|
(4,145
|
)
|
||
Revisions
|
56,611
|
|
|
(5,333
|
)
|
||
Ending balance
|
$
|
149,227
|
|
|
$
|
95,548
|
|
|
Berry Corp. (Successor)
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Proved properties
|
$
|
1,361,814
|
|
|
$
|
1,073,959
|
|
Unproved properties
|
313,903
|
|
|
388,034
|
|
||
Total proved and unproved properties
|
1,675,717
|
|
|
1,461,993
|
|
||
Less accumulated depletion and amortization
|
(209,105
|
)
|
|
(123,217
|
)
|
||
Total proved and unproved properties, net
|
$
|
1,466,612
|
|
|
$
|
1,338,776
|
|
|
Berry Corp. (Successor)
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Cogens, natural gas plants and pipelines
|
$
|
94,619
|
|
|
$
|
86,562
|
|
Buildings and leasehold improvements
|
3,752
|
|
|
3,359
|
|
||
Vehicles and service equipment
|
9,124
|
|
|
6,753
|
|
||
Furniture and equipment
|
20,078
|
|
|
14,964
|
|
||
Land
|
7,544
|
|
|
8,073
|
|
||
Total other property and equipment
|
135,117
|
|
|
119,710
|
|
||
Less: accumulated depreciation
|
(25,462
|
)
|
|
(15,778
|
)
|
||
Total other property and equipment, net
|
$
|
109,655
|
|
|
$
|
103,932
|
|
|
December 31, 2019
|
|
December 31, 2018
|
Interest Rate
|
Maturity
|
Security
|
||||
|
(in thousands)
|
|
|
|
||||||
RBL Facility
|
$
|
1,850
|
|
|
$
|
—
|
|
variable rates of 5.5% (2019) and 4.5% (2018), respectively
|
June 29, 2022
|
Mortgage on 85% of Present Value of proven oil and gas reserves
|
2026 Notes
|
400,000
|
|
|
400,000
|
|
7.0%
|
February 15, 2026
|
Unsecured
|
||
Long-Term Debt - Principal Amount
|
401,850
|
|
|
400,000
|
|
|
|
|
||
Less: Debt Issuance Costs
|
(7,531
|
)
|
|
(8,214
|
)
|
|
|
|
||
Long-Term Debt, net
|
$
|
394,319
|
|
|
$
|
391,786
|
|
|
|
|
•
|
incur or guarantee additional indebtedness or issue certain types of preferred stock;
|
•
|
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;
|
•
|
transfer, sell or dispose of assets;
|
•
|
make investments;
|
•
|
create certain liens securing indebtedness;
|
•
|
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
|
•
|
consolidate, merge or transfer all or substantially all of our assets; and
|
•
|
engage in transactions with affiliates.
|
|
Q1 2020
|
|
Q2 2020
|
|
Q3 2020
|
|
Q4 2020
|
|
FY 2021
|
||||||||||
Fixed Price Oil Swaps (Brent):
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged volume (MBbls)
|
1,729
|
|
|
1,456
|
|
|
1,472
|
|
|
1,472
|
|
|
730
|
|
|||||
Weighted-average price ($/Bbl)
|
$
|
63.92
|
|
|
$
|
64.30
|
|
|
$
|
64.21
|
|
|
$
|
64.21
|
|
|
$
|
58.50
|
|
Fixed Price Oil Swaps (WTI):
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged volume (MBbls)
|
91
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Weighted-average price ($/Bbl)
|
$
|
61.75
|
|
|
$
|
61.75
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Fixed Price Gas Purchase Swaps (Kern, Delivered):
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged volume (MMBtu)
|
5,005,000
|
|
|
5,005,000
|
|
|
5,060,000
|
|
|
2,315,000
|
|
|
900,000
|
|
|||||
Weighted-average price ($/MMBtu)
|
$
|
2.89
|
|
|
$
|
2.89
|
|
|
$
|
2.89
|
|
|
$
|
2.79
|
|
|
$
|
2.50
|
|
Fixed Price Gas Purchase Swaps (SoCal Citygate):
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged volume (MMBtu)
|
455,000
|
|
|
455,000
|
|
|
460,000
|
|
|
155,000
|
|
|
—
|
|
|||||
Weighted-average price ($/MMBtu)
|
$
|
3.80
|
|
|
$
|
3.80
|
|
|
$
|
3.80
|
|
|
$
|
3.80
|
|
|
$
|
—
|
|
|
Berry Corp. (Successor)
|
||||||||||||
|
December 31, 2019
|
||||||||||||
|
Balance Sheet Classification
|
|
Gross Amounts Recognized at Fair Value
|
|
Gross Amounts Offset on Balance Sheet
|
|
Net Fair Value Presented on Balance Sheet
|
||||||
|
(in thousands)
|
||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||
Commodity Contracts
|
Current assets
|
|
$
|
17,799
|
|
|
$
|
(8,633
|
)
|
|
$
|
9,166
|
|
Commodity Contracts
|
Non-current assets
|
|
773
|
|
|
(248
|
)
|
|
525
|
|
|||
Liabilities:
|
|
|
|
|
|
|
|
||||||
Commodity Contracts
|
Current liabilities
|
|
(13,450
|
)
|
|
8,633
|
|
|
(4,817
|
)
|
|||
Commodity Contracts
|
Non-current liabilities
|
|
(389
|
)
|
|
248
|
|
|
(141
|
)
|
|||
Total derivatives
|
|
|
$
|
4,733
|
|
|
$
|
—
|
|
|
$
|
4,733
|
|
|
Berry Corp. (Successor)
|
||||||||||||
|
December 31, 2018
|
||||||||||||
|
Balance Sheet Classification
|
|
Gross Amounts Recognized at Fair Value
|
|
Gross Amounts Offset in the Balance Sheet
|
|
Net Fair Value Presented in the Balance Sheet
|
||||||
|
(in thousands)
|
||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||
Commodity Contracts
|
Current assets
|
|
$
|
89,981
|
|
|
$
|
(1,385
|
)
|
|
$
|
88,596
|
|
Commodity Contracts
|
Non-current assets
|
|
3,289
|
|
|
—
|
|
|
3,289
|
|
|||
Liabilities:
|
|
|
|
|
|
|
|
||||||
Commodity Contracts
|
Current liabilities
|
|
(1,385
|
)
|
|
1,385
|
|
|
—
|
|
|||
Total derivatives
|
|
|
$
|
91,885
|
|
|
$
|
—
|
|
|
$
|
91,885
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
|
(in thousands)
|
|||||||||||||||
(Losses) gains on oil derivatives
|
$
|
(37,998
|
)
|
|
$
|
(4,621
|
)
|
|
$
|
(66,900
|
)
|
|
|
$
|
12,886
|
|
(Losses) gains on natural gas derivatives
|
(6,957
|
)
|
|
6,357
|
|
|
—
|
|
|
|
—
|
|
||||
Total (losses) gains on oil and natural gas derivatives
|
$
|
(44,955
|
)
|
|
$
|
1,735
|
|
|
$
|
(66,900
|
)
|
|
|
$
|
12,886
|
|
|
2020
|
2021
|
2022
|
2023
|
2024
|
Thereafter
|
Total
|
||||||||||||||
|
(in thousands)
|
||||||||||||||||||||
Minimum purchase obligations(1)
|
$
|
7,136
|
|
$
|
2,675
|
|
$
|
2,590
|
|
$
|
1,061
|
|
$
|
—
|
|
$
|
—
|
|
$
|
13,462
|
|
Minimum lease payments
|
$
|
1,723
|
|
$
|
1,731
|
|
$
|
1,740
|
|
$
|
1,647
|
|
$
|
1,420
|
|
$
|
3,708
|
|
$
|
11,969
|
|
(1)
|
Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure transportation of our natural gas production to market as well as pipeline and processing capacity.
|
|
Number of shares
|
|
Weighted-average Grant Date Fair Value
|
|||
|
(shares in thousands)
|
|||||
Non-vested at December 31, 2018
|
641
|
|
|
$
|
10.82
|
|
Granted
|
767
|
|
|
$
|
12.62
|
|
Vested
|
(308
|
)
|
|
$
|
10.87
|
|
Forfeited
|
(86
|
)
|
|
$
|
12.19
|
|
Non-vested at December 31, 2019
|
1,014
|
|
|
$
|
12.05
|
|
|
Number of shares
|
|
Weighted-average Grant Date Fair Value
|
|||
|
(shares in thousands)
|
|||||
Non-vested at December 31, 2018
|
282
|
|
|
$
|
6.73
|
|
Granted
|
554
|
|
|
$
|
12.75
|
|
Vested
|
—
|
|
|
$
|
—
|
|
Forfeited
|
(38
|
)
|
|
$
|
9.69
|
|
Non-vested at December 31, 2019
|
798
|
|
|
$
|
10.77
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
|
(in thousands)
|
|||||||||||||||
Current taxes:
|
|
|
|
|
|
|
|
|
||||||||
Federal
|
$
|
—
|
|
|
$
|
(465
|
)
|
|
$
|
465
|
|
|
|
$
|
—
|
|
State
|
227
|
|
|
(446
|
)
|
|
450
|
|
|
|
221
|
|
||||
Total current taxes
|
227
|
|
|
(911
|
)
|
|
915
|
|
|
|
221
|
|
||||
Deferred taxes:
|
|
|
|
|
|
|
|
|
||||||||
Federal
|
(36,756
|
)
|
|
33,227
|
|
|
1,888
|
|
|
|
—
|
|
||||
State
|
(21
|
)
|
|
10,719
|
|
|
—
|
|
|
|
9
|
|
||||
Total deferred taxes
|
(36,777
|
)
|
|
43,946
|
|
|
1,888
|
|
|
|
9
|
|
||||
Total current and deferred taxes
|
$
|
(36,550
|
)
|
|
$
|
43,035
|
|
|
$
|
2,803
|
|
|
|
$
|
230
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||
Federal statutory rate
|
21.0
|
%
|
|
21.0
|
%
|
|
35.0
|
%
|
|
|
35.0
|
%
|
State, net of federal tax benefit
|
8.9
|
%
|
|
6.3
|
%
|
|
7.2
|
%
|
|
|
—
|
%
|
Effect of permanent differences
|
0.2
|
%
|
|
(0.6
|
)%
|
|
(0.4
|
)%
|
|
|
—
|
%
|
Tax credits and federal return to provision
|
(546.4
|
)%
|
|
—
|
%
|
|
—
|
%
|
|
|
—
|
%
|
State return to provision
|
(6.6
|
)%
|
|
—
|
%
|
|
—
|
%
|
|
|
—
|
%
|
Tax reform—rate change(1)
|
—
|
%
|
|
—
|
%
|
|
(14.7
|
)%
|
|
|
—
|
%
|
Income excluded from nontaxable entities
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
|
(35.0
|
)%
|
Change in valuation allowance
|
—
|
%
|
|
(4.1
|
)%
|
|
(42.4
|
)%
|
|
|
—
|
%
|
Effective tax rate
|
(522.9
|
)%
|
|
22.6
|
%
|
|
(15.3
|
)%
|
|
|
—
|
%
|
(1)
|
For the ten months ended December 31, 2017, includes the tax rate reduction. The impact of the rate change is fully offset in the “Change in valuation allowance” item.
|
|
Berry Corp. (Successor)
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Deferred tax assets:
|
|
|
|
||||
Net operating loss carryforwards
|
$
|
14,542
|
|
|
$
|
14,310
|
|
Accruals
|
12,218
|
|
|
2,993
|
|
||
Asset retirement obligations
|
41,382
|
|
|
26,383
|
|
||
Tax credits and federal return to provision
|
47,803
|
|
|
—
|
|
||
Interest limitation carryforward
|
13,892
|
|
|
7,486
|
|
||
Other
|
5,154
|
|
|
2,033
|
|
||
Total deferred tax assets
|
134,991
|
|
|
53,205
|
|
||
Deferred tax liabilities:
|
|
|
|
||||
Book tax differences in property basis
|
(143,896
|
)
|
|
(95,348
|
)
|
||
Derivative instruments
|
(152
|
)
|
|
(3,692
|
)
|
||
Total deferred tax liabilities
|
(144,048
|
)
|
|
(99,040
|
)
|
||
Net deferred tax asset (liability)
|
$
|
(9,057
|
)
|
|
$
|
(45,835
|
)
|
|
Berry Corp. (Successor)
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Unrecognized tax benefits - January 1
|
$
|
—
|
|
|
$
|
—
|
|
Prior year - increase
|
6,720
|
|
|
—
|
|
||
Current year - increase
|
7,172
|
|
|
—
|
|
||
Unrecognized tax benefits - December 31
|
$
|
13,892
|
|
|
$
|
—
|
|
|
Berry Corp. (Successor)
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Prepaid expenses
|
$
|
4,577
|
|
|
$
|
4,656
|
|
Materials and supplies
|
10,544
|
|
|
5,461
|
|
||
Oil inventories
|
3,432
|
|
|
3,786
|
|
||
Other
|
846
|
|
|
464
|
|
||
Other current assets
|
$
|
19,399
|
|
|
$
|
14,367
|
|
|
Berry Corp. (Successor)
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Accounts payable-trade
|
$
|
25,475
|
|
|
$
|
13,564
|
|
Accrued expenses
|
45,589
|
|
|
66,417
|
|
||
Royalties payable
|
25,385
|
|
|
26,189
|
|
||
Taxes other than income tax liability
|
9,150
|
|
|
10,766
|
|
||
Accrued interest
|
10,500
|
|
|
10,500
|
|
||
Dividends payable
|
9,888
|
|
|
9,992
|
|
||
Asset retirement obligation - current portion
|
25,208
|
|
|
6,372
|
|
||
Other
|
616
|
|
|
318
|
|
||
Total accounts payable and accrued expenses
|
$
|
151,811
|
|
|
$
|
144,118
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
|
(in thousands)
|
|||||||||||||||
Supplemental Disclosures of Significant Non-Cash Investing Activities:
|
|
|
|
|
|
|
|
|
||||||||
Material inventory transfers to oil and natural gas properties
|
$
|
10,056
|
|
|
$
|
2,371
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
Supplemental Disclosures of Cash Payments (Receipts):
|
|
|
|
|
|
|
|
|
||||||||
Interest, net of amounts capitalized
|
$
|
30,720
|
|
|
$
|
19,761
|
|
|
$
|
14,276
|
|
|
|
$
|
8,057
|
|
Income taxes
|
$
|
(2
|
)
|
|
$
|
(1,901
|
)
|
|
$
|
1,994
|
|
|
|
$
|
—
|
|
Reorganization items, net
|
$
|
—
|
|
|
$
|
832
|
|
|
$
|
1,732
|
|
|
|
$
|
11,838
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
|
(in thousands)
|
|||||||||||||||
Beginning of Period
|
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
68,680
|
|
|
$
|
33,905
|
|
|
$
|
32,049
|
|
|
|
$
|
30,483
|
|
Restricted cash
|
—
|
|
|
34,833
|
|
|
52,860
|
|
|
|
197,793
|
|
||||
Restricted cash in other noncurrent assets
|
—
|
|
|
—
|
|
|
125
|
|
|
|
128
|
|
||||
Cash, cash equivalents and restricted cash
|
$
|
68,680
|
|
|
$
|
68,738
|
|
|
$
|
85,034
|
|
|
|
$
|
228,404
|
|
|
|
|
|
|
|
|
|
|
||||||||
Ending of Period
|
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
68,680
|
|
|
$
|
33,905
|
|
|
|
$
|
32,049
|
|
Restricted cash
|
—
|
|
|
—
|
|
|
34,833
|
|
|
|
52,860
|
|
||||
Restricted cash in other noncurrent assets
|
—
|
|
|
—
|
|
|
—
|
|
|
|
125
|
|
||||
Cash, cash equivalents and restricted cash
|
$
|
—
|
|
|
$
|
68,680
|
|
|
$
|
68,738
|
|
|
|
$
|
85,034
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||
|
(in thousands except per share amounts)
|
|||||||||||||
Basic EPS calculation
|
|
|
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
43,539
|
|
|
$
|
147,102
|
|
|
$
|
(21,068
|
)
|
|
|
n/a
|
less: Series A Preferred Stock dividends and conversion to common stock
|
—
|
|
|
(97,942
|
)
|
|
(18,248
|
)
|
|
|
n/a
|
|||
Net income (loss) attributable to common stockholders
|
$
|
43,539
|
|
|
$
|
49,160
|
|
|
$
|
(39,316
|
)
|
|
|
n/a
|
Weighted-average shares of common stock outstanding(1)
|
81,379
|
|
|
57,743
|
|
|
38,644
|
|
|
|
n/a
|
|||
Basic earnings (loss) per share(2)
|
$
|
0.54
|
|
|
$
|
0.85
|
|
|
$
|
(1.02
|
)
|
|
|
n/a
|
Diluted EPS calculation
|
|
|
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
43,539
|
|
|
$
|
147,102
|
|
|
$
|
(21,068
|
)
|
|
|
n/a
|
less: Series A Preferred Stock dividends and conversion to common stock
|
—
|
|
|
(97,942
|
)
|
|
(18,248
|
)
|
|
|
n/a
|
|||
Net income (loss) attributable to common stockholders
|
$
|
43,539
|
|
|
$
|
49,160
|
|
|
$
|
(39,316
|
)
|
|
|
n/a
|
Weighted-average shares of common stock outstanding(1)
|
81,379
|
|
|
57,743
|
|
|
38,644
|
|
|
|
n/a
|
|||
Dilutive effect of potentially dilutive securities(3)
|
572
|
|
|
189
|
|
|
—
|
|
|
|
n/a
|
|||
Weighted-average common shares outstanding - diluted
|
81,951
|
|
|
57,932
|
|
|
38,644
|
|
|
|
n/a
|
|||
Diluted earnings (loss) per share(2)
|
$
|
0.53
|
|
|
$
|
0.85
|
|
|
$
|
(1.02
|
)
|
|
|
n/a
|
(1)
|
For the year ended December 31, 2018, we retrospectively adjusted the weighted average shares in our earnings per share calculations for the 2,770,000 shares issued instead of 7,080,000 shares that had been reserved for the year ended December 31, 2018 and the ten months ended December 31, 2017.
|
(2)
|
Per share amounts are stated net of tax.
|
(3)
|
No potentially dilutive securities were included in computing earnings (loss) per share for the ten months ended December 31, 2017 because the effect of inclusion would have been anti-dilutive.
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
|
(in thousands)
|
|||||||||||||||
Oil sales
|
$
|
543,634
|
|
|
$
|
520,979
|
|
|
$
|
303,589
|
|
|
|
$
|
54,110
|
|
Natural gas sales
|
19,391
|
|
|
26,244
|
|
|
40,887
|
|
|
|
14,476
|
|
||||
Natural gas liquids sales
|
2,571
|
|
|
5,651
|
|
|
13,452
|
|
|
|
5,534
|
|
||||
Electricity sales
|
29,397
|
|
|
35,208
|
|
|
21,972
|
|
|
|
3,655
|
|
||||
Marketing revenues
|
2,094
|
|
|
2,322
|
|
|
2,694
|
|
|
|
633
|
|
||||
Other revenues
|
316
|
|
|
774
|
|
|
3,975
|
|
|
|
1,424
|
|
||||
Revenues from contracts with customers
|
597,403
|
|
|
591,178
|
|
|
386,569
|
|
|
|
79,832
|
|
||||
(Losses) gains on oil derivatives
|
(37,998
|
)
|
|
(4,621
|
)
|
|
(66,900
|
)
|
|
|
12,886
|
|
||||
Total revenues and other
|
$
|
559,405
|
|
|
$
|
586,557
|
|
|
$
|
319,669
|
|
|
|
$
|
92,718
|
|
•
|
Linn Acquisition Company, LLC transferred 100% of the outstanding membership interests in Berry LLC to Berry Corp. pursuant to an assignment agreement, dated February 28, 2017 between Linn Acquisition Company, LLC and Berry Corp. (the “Assignment Agreement”). Under the Assignment Agreement, Berry LLC became a wholly-owned operating subsidiary of Berry Corp.
|
•
|
The holders of claims under the Company’s Second Amended and Restated Credit Agreement, dated November 15, 2010, by and among Berry LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and certain lenders, (as amended, the “Pre-Emergence Credit Facility”), received (i) their pro-rated share of a cash paydown and (ii) pro-rated participation in the new facility (the “Emergence Credit Facility”). As a result, all outstanding obligations under the Pre-Emergence Credit Facility were canceled and the agreements governing these obligations were terminated.
|
•
|
Berry LLC, as borrower, entered into the Emergence Credit Facility with the holders of claims under the Pre-Emergence Credit Facility, as lenders, and Wells Fargo Bank, N.A, as administrative agent, providing for a new reserves-based revolving loan with up to $550 million in borrowing commitments. This facility was replaced with the RBL Facility in July 2017 noted above.
|
•
|
The holders of Berry LLC’s 6.75% senior notes due 2020, issued by Berry LLC pursuant to a Second Supplemental Indenture, dated November 1, 2010, and 6.375% senior notes due 2022, issued by Berry LLC pursuant to a Third Supplemental Indenture, dated March 9, 2012 (collectively, the “Unsecured Notes”), received a right to their pro-rated share of either (i) 32,920,000 shares of common stock in Berry Corp. or, for those non-accredited investors holding the Unsecured Notes that irrevocably elected to receive a cash recovery, cash distributions from a $35 million cash distribution pool (the “Cash Distribution Pool”) and (ii) specified rights to participate in a two-tranche offering of rights to purchase Series A Preferred Stock at an aggregate purchase price of $335 million (as further defined in the Plan, the “Berry Rights Offerings”). As a result, all outstanding obligations under the Unsecured Notes were canceled and the indentures and related agreements governing these obligations were terminated.
|
•
|
The holders of unsecured claims against Berry LLC, (other than the Unsecured Notes) (the “Unsecured Claims”) received a right to their pro-rated share of either (i) 7,080,000 shares of common stock in Berry Corp. or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool. After the Effective Date we have negotiated with claimants to settle their claims. As a result, in early 2019, we issued 2,770,000 shares to settle these claims for which we had originally reserved 7,080,000 shares.
|
•
|
Berry LLC settled all intercompany claims against Linn Energy and its affiliates pursuant to a settlement agreement approved as part of the Plan and the Confirmation Order. The settlement agreement provided Berry LLC with a $25 million general unsecured claim against Linn Energy which Berry LLC has fully-reserved.
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
|
(in thousands)
|
|||||||||||||||
Return of undistributed funds from cash distribution pool(1)
|
$
|
—
|
|
|
$
|
22,855
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
Gains on resolution of pre-emergence liabilities and claims
|
—
|
|
|
3,713
|
|
|
—
|
|
|
|
—
|
|
||||
Legal and other professional advisory fees
|
(426
|
)
|
|
(3,083
|
)
|
|
(1,027
|
)
|
|
|
(19,481
|
)
|
||||
Gains on settlement of liabilities subject to compromise
|
—
|
|
|
—
|
|
|
—
|
|
|
|
421,774
|
|
||||
Fresh-start valuation adjustments
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(920,699
|
)
|
||||
Other
|
—
|
|
|
1,205
|
|
|
(705
|
)
|
|
|
10,686
|
|
||||
Reorganization items, net
|
$
|
(426
|
)
|
|
$
|
24,690
|
|
|
$
|
(1,732
|
)
|
|
|
$
|
(507,720
|
)
|
(1)
|
This amount was reclassed from restricted cash to general cash, thus does not represent a cash transaction.
|
|
(in thousands)
|
||
Enterprise value
|
$
|
1,278,527
|
|
Plus: Fair value of non-debt liabilities
|
282,511
|
|
|
Reorganization value of the Successor’s assets
|
$
|
1,561,038
|
|
|
As of February 28, 2017
|
||||||||||||||||
|
Berry LLC (Predecessor)
|
|
Reorganization Adjustments(1)
|
|
Fresh-Start Adjustments
|
|
Berry Corp. (Successor)
|
||||||||||
|
(in thousands)
|
||||||||||||||||
ASSETS
|
|
|
|
|
|
|
|
||||||||||
Current assets:
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
27,407
|
|
|
$
|
4,642
|
|
(2)
|
$
|
—
|
|
|
$
|
32,049
|
|
||
Accounts receivable
|
76,027
|
|
|
(15,700
|
)
|
(3)
|
(816
|
)
|
(14
|
)
|
59,511
|
|
|||||
Derivative instruments
|
243
|
|
|
—
|
|
|
—
|
|
|
243
|
|
||||||
Restricted cash
|
128
|
|
|
52,732
|
|
(4)
|
—
|
|
|
52,860
|
|
||||||
Other current assets
|
18,437
|
|
|
(5,558
|
)
|
(5)
|
3,873
|
|
(15
|
)
|
16,752
|
|
|||||
Total current assets
|
122,242
|
|
|
36,116
|
|
|
3,057
|
|
|
161,415
|
|
||||||
Non-current assets:
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas properties
|
5,031,498
|
|
|
—
|
|
|
(3,787,898
|
)
|
(16
|
)
|
1,243,600
|
|
|||||
Less accumulated depletion and amortization
|
(2,814,999
|
)
|
|
—
|
|
|
2,814,999
|
|
(16
|
)
|
—
|
|
|||||
Total oil and natural gas properties, net
|
2,216,499
|
|
|
—
|
|
|
(972,899
|
)
|
|
1,243,600
|
|
||||||
Other property and equipment
|
124,379
|
|
|
—
|
|
|
(15,576
|
)
|
(17
|
)
|
108,803
|
|
|||||
Less accumulated depreciation
|
(22,107
|
)
|
|
—
|
|
|
22,107
|
|
(17
|
)
|
—
|
|
|||||
Total other property and equipment, net
|
102,273
|
|
|
—
|
|
|
6,530
|
|
|
108,803
|
|
||||||
Derivative instruments
|
57
|
|
|
—
|
|
|
—
|
|
|
57
|
|
||||||
Restricted cash
|
197,939
|
|
|
(197,814
|
)
|
(2)
|
—
|
|
|
125
|
|
||||||
Other non-current assets
|
16,076
|
|
|
151
|
|
(6)
|
30,811
|
|
(18
|
)
|
47,038
|
|
|||||
Total assets
|
$
|
2,655,086
|
|
|
$
|
(161,547
|
)
|
|
$
|
(932,501
|
)
|
|
$
|
1,561,038
|
|
||
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
||||||||||
Current liabilities:
|
|
|
|
|
|
|
|
||||||||||
Accounts payable and accrued expenses
|
$
|
60,323
|
|
|
$
|
52,371
|
|
(7)
|
$
|
3,818
|
|
(19
|
)
|
$
|
116,512
|
|
|
Derivative instruments
|
5,355
|
|
|
—
|
|
|
—
|
|
|
5,355
|
|
||||||
Current portion of long-term debt, net
|
891,259
|
|
|
(891,259
|
)
|
(8)
|
—
|
|
|
—
|
|
||||||
Other accrued liabilities
|
7,335
|
|
|
(3,760
|
)
|
(9)
|
1,295
|
|
(20
|
)
|
4,870
|
|
|||||
Total current liabilities
|
964,272
|
|
|
(842,648
|
)
|
|
5,113
|
|
|
126,737
|
|
||||||
Non-current liabilities:
|
|
|
|
|
|
|
|
||||||||||
Derivative instruments
|
1,710
|
|
|
—
|
|
|
—
|
|
|
1,710
|
|
||||||
Long-term debt
|
—
|
|
|
400,000
|
|
(10
|
)
|
—
|
|
|
400,000
|
|
|||||
Other non-current liabilities
|
170,979
|
|
|
—
|
|
|
(16,915
|
)
|
(21
|
)
|
154,064
|
|
|||||
Liabilities subject to compromise
|
1,000,336
|
|
|
(1,000,336
|
)
|
(11
|
)
|
—
|
|
|
—
|
|
|||||
Equity:
|
|
|
|
|
|
|
|
||||||||||
Predecessor additional paid-in capital
|
2,798,714
|
|
|
(2,798,714
|
)
|
(12
|
)
|
—
|
|
|
—
|
|
|||||
Predecessor accumulated deficit
|
(2,280,925
|
)
|
|
375,159
|
|
(13
|
)
|
1,905,766
|
|
(22
|
)
|
—
|
|
||||
Successor preferred stock
|
—
|
|
|
335,000
|
|
(12
|
)
|
—
|
|
|
335,000
|
|
|||||
Successor common stock
|
—
|
|
|
33
|
|
(12
|
)
|
—
|
|
|
33
|
|
|||||
Successor additional paid-in capital
|
—
|
|
|
3,369,959
|
|
(12
|
)
|
(2,826,465
|
)
|
(22
|
)
|
543,494
|
|
||||
Total equity
|
517,789
|
|
|
1,281,437
|
|
|
(920,699
|
)
|
|
878,527
|
|
||||||
Total liabilities and equity
|
$
|
2,655,086
|
|
|
$
|
(161,547
|
)
|
|
$
|
(932,501
|
)
|
|
$
|
1,561,038
|
|
(1)
|
Represent amounts recorded as of the Effective Date for the implementation of the Plan, including, among other items, settlement of the Predecessor’s liabilities subject to compromise, repayment of certain of the Predecessor’s debt, cancellation of the Predecessor’s equity, issuances of the Successor’s common stock and preferred stock, proceeds received from the Berry Rights Offerings and issuance of the Successor’s debt.
|
(2)
|
Changes in cash and cash equivalents included the following:
|
|
(in thousands)
|
||
Borrowings under the Emergence Credit Facility
|
$
|
400,000
|
|
Proceeds from issuance of preferred stock pursuant the Berry Rights Offerings
|
335,000
|
|
|
Cash receipt from Linn Energy, LLC for ad valorem taxes
|
23,366
|
|
|
Removal of restriction on cash balance (includes $128 previously recorded as short term)
|
197,942
|
|
|
Payment to the holders of claims under the Pre-Emergence Credit Facility (including $29 in bank fees and $3,760 in interest)
|
(897,663)
|
|
|
Payment of professional fees
|
(992)
|
|
|
Payment of Emergence Credit Facility fee that was capitalized
|
(151)
|
|
|
Funding of the general unsecured claims Cash Distribution Pool
|
(35,000)
|
|
|
Funding of the professional fees escrow account
|
(17,860)
|
|
|
Changes in cash and cash equivalents
|
$
|
4,642
|
|
(3)
|
Collection of overpayment to Linn Energy, LLC for ad valorem taxes.
|
(4)
|
Primarily reflects the transfer to restricted cash to fund the Predecessor’s professional fees escrow account and general unsecured claims Cash Distribution Pool.
|
(5)
|
Primarily reflects the write-off of the Predecessor’s deferred financing fees.
|
(6)
|
Reflects the capitalization of deferred financing fees related to the Emergence Credit Facility.
|
(7)
|
Net increase in accounts payable and accrued expenses reflects:
|
|
(in thousands)
|
||
Recognition of payables for the general unsecured claims Cash Distribution Pool
|
$
|
35,000
|
|
Recognition of payables for the professional fees escrow account
|
17,860
|
|
|
Recognition of payable for ad valorem tax liability
|
7,666
|
|
|
Net change of other professional fees payable
|
(8,161)
|
|
|
Other
|
6
|
|
|
Net increase in accounts payable and accrued expenses
|
$
|
52,371
|
|
(8)
|
Reflects the repayment of the Pre-Emergence Credit Facility.
|
(9)
|
Reflects the payment of accrued interest on the Pre-Emergence Credit Facility.
|
(10)
|
Reflects borrowings under the Emergence Credit Facility.
|
(11)
|
Settlement of liabilities subject to compromise and the resulting net gains were determined as follows:
|
|
(in thousands)
|
||
Accounts payable and accrued expenses
|
$
|
151,298
|
|
Accrued interest payable
|
15,238
|
|
|
Debt
|
833,800
|
|
|
Total liabilities subject to compromise
|
1,000,336
|
|
|
Funding of the general unsecured claims Cash Distribution Pool
|
(35,000)
|
|
|
Common stock to holders of Unsecured Notes and general unsecured creditors
|
(543,562)
|
|
|
Gains on settlement of liabilities subject to compromise
|
$
|
421,774
|
|
(12)
|
Net increase in capital accounts reflects:
|
|
(in thousands)
|
||
Common stock to holders of Unsecured Notes and general unsecured creditors
|
$
|
543,562
|
|
Payment of issuance costs
|
(35)
|
|
|
Dividend related to beneficial conversion feature of preferred stock
|
27,751
|
|
|
Cancellation of the Predecessor’s additional paid-in capital
|
2,798,714
|
|
|
Par value of common stock
|
(33)
|
|
|
Change in additional paid-in capital
|
3,369,959
|
|
|
Proceeds from issuance of preferred stock
|
335,000
|
|
|
Par value of common stock
|
33
|
|
|
Predecessor’s additional paid-in capital
|
(2,798,714)
|
|
|
Net increase in capital accounts
|
$
|
906,278
|
|
(13)
|
Net decrease in accumulated deficit reflects:
|
|
(in thousands)
|
||
Recognition of gains on settlement of liabilities subject to compromise
|
$
|
421,774
|
|
Recognition of professional fees
|
(13,667)
|
|
|
Write-off of deferred financing fees
|
(5,197)
|
|
|
Total reorganization items, net
|
402,910
|
|
|
Dividend related to beneficial conversion feature of preferred stock
|
(27,751
|
)
|
|
Net decrease in accumulated deficit
|
$
|
375,159
|
|
(14)
|
Reflects a change in accounting policy from the entitlements method to the sales method for natural gas production imbalances.
|
(15)
|
Primarily reflects an increase in the current portion of greenhouse gas allowances.
|
(16)
|
Reflects a decrease of oil and natural gas properties, based on the methodology discussed in Note 2, and the elimination of accumulated depletion and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date:
|
|
Berry Corp. (Successor)
|
|
|
Berry LLC (Predecessor)
|
||||
|
Fair Value
|
|
|
Historical Book Value
|
||||
|
(in thousands)
|
|||||||
Proved properties
|
$
|
712,400
|
|
|
|
$
|
4,266,843
|
|
Unproved properties
|
531,200
|
|
|
|
764,655
|
|
||
Total proved and unproved properties
|
1,243,600
|
|
|
|
5,031,498
|
|
||
Less accumulated depletion and amortization
|
—
|
|
|
|
(2,814,999
|
)
|
||
Total proved and unproved properties, net
|
$
|
1,243,600
|
|
|
|
$
|
2,216,499
|
|
(17)
|
Reflects a decrease of other property and equipment and the elimination of accumulated depreciation. The following table summarizes the components of other property and equipment as of the Effective Date:
|
|
Berry Corp. (Successor)
|
|
|
Berry LLC (Predecessor)
|
||||
|
Fair Value
|
|
|
Historical Book Value
|
||||
|
(in thousands)
|
|||||||
Natural gas plants and pipelines
|
$
|
91,427
|
|
|
|
$
|
109,675
|
|
Land
|
8,262
|
|
|
|
201
|
|
||
Furniture and office equipment
|
5,040
|
|
|
|
3,879
|
|
||
Buildings and leasehold improvements
|
2,740
|
|
|
|
5,884
|
|
||
Vehicles
|
1,156
|
|
|
|
4,542
|
|
||
Drilling and other equipment
|
178
|
|
|
|
198
|
|
||
Total other property and equipment
|
108,803
|
|
|
|
124,379
|
|
||
Less accumulated depreciation
|
—
|
|
|
|
(22,107
|
)
|
||
Total other property and equipment, net
|
$
|
108,803
|
|
|
|
$
|
102,273
|
|
(18)
|
Primarily reflects an increase in greenhouse gas allowances of approximately $30 million and a joint venture investment of approximately $1 million. Greenhouse gas allowances were valued using a market approach based on trading prices for carbon credits on February 28, 2017. Our joint venture investment was valued based on a market approach using a market EBITDA multiple.
|
(19)
|
Reflects increases for greenhouse gas emissions liabilities of approximately $4 million and a change in accounting policy from the entitlements method to the sales method for gas production imbalances of approximately $200,000, partially offset by a decrease for the current portion of intangibles liabilities of approximately $500,000.
|
(20)
|
Reflects an increase of the current portion of asset retirement obligations.
|
(21)
|
Primarily reflects a decrease for asset retirement obligations of approximately $30 million and for intangible liabilities of approximately$6 million, partially offset by an increase for greenhouse gas emissions liabilities of approximately $19 million. The fair value of asset retirement obligations was estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plugging and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. The intangible liabilities identified on the Effective Date were valued based on a combination of market and incomes approaches and will be amortized over the remaining life of the respective contract. Greenhouse gas emissions liabilities were valued using a market approach based on trading prices for greenhouse gas allowances on February 28, 2017.
|
(22)
|
Reflects the cumulative impact of the fresh-start accounting adjustments discussed above and the elimination of the Predecessor’s accumulated deficit.
|
|
Berry Corp. (Successor)
|
||||||||||||||
|
Quarters Ended
|
||||||||||||||
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|||||||||
|
(in thousands, except per share amounts)
|
||||||||||||||
2019:
|
|
|
|
|
|
|
|
||||||||
Oil, natural gas and natural gas liquid sales
|
$
|
131,102
|
|
|
$
|
136,908
|
|
|
$
|
141,250
|
|
|
$
|
156,336
|
|
Electricity sales
|
$
|
9,729
|
|
|
$
|
5,364
|
|
|
$
|
7,460
|
|
|
$
|
6,844
|
|
(Losses) gains on oil derivatives
|
$
|
(65,239
|
)
|
|
$
|
27,276
|
|
|
$
|
45,509
|
|
|
$
|
(45,544
|
)
|
Marketing revenues
|
$
|
830
|
|
|
$
|
414
|
|
|
$
|
413
|
|
|
$
|
437
|
|
Other revenues
|
$
|
117
|
|
|
$
|
104
|
|
|
$
|
40
|
|
|
$
|
55
|
|
Total expenses(2)
|
$
|
114,853
|
|
|
$
|
116,886
|
|
|
$
|
113,008
|
|
|
$
|
173,089
|
|
Total other (expenses) income
|
$
|
(8,651
|
)
|
|
$
|
(8,961
|
)
|
|
$
|
(8,674
|
)
|
|
$
|
(7,868
|
)
|
Reorganization items, net, (income) expense
|
$
|
(231
|
)
|
|
$
|
(26
|
)
|
|
$
|
(170
|
)
|
|
$
|
—
|
|
Net (loss) income
|
$
|
(34,098
|
)
|
|
$
|
31,972
|
|
|
$
|
52,649
|
|
|
$
|
(6,984
|
)
|
Net (loss) income attributable to common stockholders
|
$
|
(34,098
|
)
|
|
$
|
31,972
|
|
|
$
|
52,649
|
|
|
$
|
(6,984
|
)
|
(Loss) earnings per share attributable to common stockholders:
|
|
|
|
|
|
|
|
||||||||
Basic(1)
|
$
|
(0.42
|
)
|
|
$
|
0.39
|
|
|
$
|
0.65
|
|
|
$
|
(0.09
|
)
|
Diluted(1)
|
$
|
(0.42
|
)
|
|
$
|
0.39
|
|
|
$
|
0.65
|
|
|
$
|
(0.09
|
)
|
|
Berry Corp. (Successor)
|
||||||||||||||
|
Quarters Ended
|
||||||||||||||
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|||||||||
|
(in thousands)
|
||||||||||||||
2018:
|
|
|
|
|
|
|
|
||||||||
Oil, natural gas and natural gas liquid sales
|
$
|
125,624
|
|
|
$
|
137,385
|
|
|
$
|
147,004
|
|
|
$
|
142,861
|
|
Electricity sales
|
$
|
5,453
|
|
|
$
|
5,971
|
|
|
$
|
14,268
|
|
|
$
|
9,517
|
|
(Losses) gains on oil derivatives
|
$
|
(34,644
|
)
|
|
$
|
(78,143
|
)
|
|
$
|
(18,994
|
)
|
|
$
|
127,160
|
|
Marketing revenues
|
$
|
785
|
|
|
$
|
518
|
|
|
$
|
486
|
|
|
$
|
534
|
|
Other revenues
|
$
|
66
|
|
|
$
|
251
|
|
|
$
|
183
|
|
|
$
|
274
|
|
Total expenses
|
$
|
91,121
|
|
|
$
|
90,581
|
|
|
$
|
102,530
|
|
|
$
|
101,473
|
|
Total other (expenses) income
|
$
|
(7,769
|
)
|
|
$
|
(9,394
|
)
|
|
$
|
(9,530
|
)
|
|
$
|
(8,712
|
)
|
Reorganization items, net, expense (income)
|
$
|
8,955
|
|
|
$
|
456
|
|
|
$
|
13,781
|
|
|
$
|
1,498
|
|
Net income (loss)
|
$
|
6,410
|
|
|
$
|
(28,061
|
)
|
|
$
|
36,985
|
|
|
$
|
131,768
|
|
Net income (loss) attributable to common stockholders
|
$
|
760
|
|
|
$
|
(33,711
|
)
|
|
$
|
(49,657
|
)
|
|
$
|
131,768
|
|
Earnings (loss) per share attributable to common stockholders:
|
|
|
|
|
|
|
|
||||||||
Basic(1)
|
$
|
0.02
|
|
|
$
|
(0.94
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
1.56
|
|
Diluted(1)
|
$
|
0.02
|
|
|
$
|
(0.94
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
1.56
|
|
(1)
|
In March 2019, we finalized settlement of claims from unsecured creditors, issuing approximately 2,770,000 shares. We retrospectively adjusted the weighted average shares in our earnings per share calculations for the 2,770,000 shares issued instead of the 7,080,000 shares that had been reserved. See Note 12 of our consolidated financial statements for further information.
|
(2)
|
Total expenses for the fourth quarter of 2019 includes an impairment charge of $51 million for the Piceance gas properties in Colorado.
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
|
(in thousands)
|
|||||||||||||||
Property acquisition costs:
|
|
|
|
|
|
|
|
|
||||||||
Proved
|
$
|
2,939
|
|
|
$
|
—
|
|
|
$
|
249,338
|
|
|
|
$
|
—
|
|
Unproved
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Exploration costs
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Development costs(1)
|
279,954
|
|
|
143,002
|
|
|
60,381
|
|
|
|
4,544
|
|
||||
Total costs incurred
|
$
|
282,893
|
|
|
$
|
143,002
|
|
|
$
|
309,719
|
|
|
|
$
|
4,544
|
|
(1)
|
Included in development costs for the year ended December 31, 2019 and 2018 are non-cash additions related to the estimated future asset retirement obligations of the Company's oil and gas properties of $68.1 million and $3.4 million, respectively.
|
|
Berry Corp. (Successor)
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
(in thousands)
|
||||||
Proved properties
|
$
|
1,465,383
|
|
|
$
|
1,168,245
|
|
Unproved properties
|
313,903
|
|
|
388,034
|
|
||
Total proved and unproved properties
|
1,779,286
|
|
|
1,556,279
|
|
||
Less accumulated depreciation, depletion and amortization
|
(223,919
|
)
|
|
(132,587
|
)
|
||
Net capitalized costs
|
$
|
1,555,367
|
|
|
$
|
1,423,692
|
|
|
Berry Corp.
(Successor) |
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
|
(in thousands)
|
|||||||||||||||
Net revenues from production:
|
|
|
|
|
|
|
|
|
||||||||
Oil, natural gas and NGL sales
|
$
|
565,596
|
|
|
$
|
552,874
|
|
|
$
|
357,928
|
|
|
|
$
|
74,120
|
|
Electricity sales
|
29,397
|
|
|
35,208
|
|
|
21,972
|
|
|
|
3,655
|
|
||||
Other production-related revenue
|
2,258
|
|
|
2,908
|
|
|
6,569
|
|
|
|
2,003
|
|
||||
Total net revenues from production
|
597,251
|
|
|
590,990
|
|
|
386,469
|
|
|
|
79,778
|
|
||||
Operating costs for production:
|
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
216,294
|
|
|
188,776
|
|
|
149,599
|
|
|
|
28,238
|
|
||||
Electricity generation expenses
|
19,490
|
|
|
20,619
|
|
|
14,894
|
|
|
|
3,197
|
|
||||
Transportation expenses
|
8,059
|
|
|
9,860
|
|
|
19,238
|
|
|
|
6,194
|
|
||||
Production-related general and administrative expenses
|
2,735
|
|
|
1,876
|
|
|
5,786
|
|
|
|
—
|
|
||||
Taxes, other than income taxes
|
40,254
|
|
|
33,117
|
|
|
34,211
|
|
|
|
5,212
|
|
||||
Other production-related costs
|
2,073
|
|
|
2,140
|
|
|
2,320
|
|
|
|
653
|
|
||||
Total operating costs for production
|
288,905
|
|
|
256,388
|
|
|
226,048
|
|
|
|
43,494
|
|
||||
Other costs:
|
|
|
|
|
|
|
|
|
||||||||
Depreciation, depletion and amortization
|
101,816
|
|
|
81,927
|
|
|
67,051
|
|
|
|
26,743
|
|
||||
Impairment of long-lived assets
|
51,081
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Other operating (income) expenses
|
4,545
|
|
|
(2,747
|
)
|
|
(22,930
|
)
|
|
|
—
|
|
||||
Total other costs
|
157,442
|
|
|
79,180
|
|
|
44,121
|
|
|
|
26,743
|
|
||||
Pretax income (loss)
|
150,904
|
|
|
255,422
|
|
|
116,300
|
|
|
|
9,541
|
|
||||
Income tax expense
|
10,084
|
|
|
69,807
|
|
|
45,887
|
|
|
|
230
|
|
||||
Results of operations
|
$
|
140,820
|
|
|
$
|
185,615
|
|
|
$
|
70,412
|
|
|
|
$
|
9,311
|
|
|
Year Ended December 31, 2019
|
||||||||||
|
Oil
MBbls |
|
NGLs
MBbls |
|
Natural Gas MMcf
|
|
Total
MBoe |
||||
Total proved reserves:
|
|
|
|
|
|
|
|
||||
Beginning of year
|
114,765
|
|
|
1,147
|
|
|
160,849
|
|
|
142,720
|
|
Extensions and discoveries
|
13,321
|
|
|
—
|
|
|
—
|
|
|
13,321
|
|
Revisions of previous estimates
|
10,759
|
|
|
160
|
|
|
(109,323
|
)
|
|
(7,302
|
)
|
Purchases of minerals in place
|
159
|
|
|
24
|
|
|
701
|
|
|
300
|
|
Sales of minerals in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(9,231
|
)
|
|
(151
|
)
|
|
(7,412
|
)
|
|
(10,617
|
)
|
End of year
|
129,773
|
|
|
1,180
|
|
|
44,815
|
|
|
138,422
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
||||
Beginning of year
|
73,203
|
|
|
1,047
|
|
|
76,331
|
|
|
86,971
|
|
End of year
|
74,102
|
|
|
1,054
|
|
|
39,063
|
|
|
81,667
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
||||
Beginning of year
|
41,562
|
|
|
100
|
|
|
84,518
|
|
|
55,749
|
|
End of year
|
55,670
|
|
|
127
|
|
|
5,752
|
|
|
56,756
|
|
|
Year Ended December 31, 2018
|
||||||||||
|
Oil
MBbls |
|
NGLs
MBbls |
|
Natural Gas MMcf
|
|
Total
MBoe |
||||
Total proved reserves:
|
|
|
|
|
|
|
|
||||
Beginning of year
|
100,596
|
|
|
1,271
|
|
|
237,104
|
|
|
141,385
|
|
Extensions and discoveries
|
21,276
|
|
|
126
|
|
|
5,762
|
|
|
22,362
|
|
Revisions of previous estimates
|
80
|
|
|
211
|
|
|
(62,141
|
)
|
|
(10,066
|
)
|
Purchases of minerals in place
|
865
|
|
|
—
|
|
|
—
|
|
|
865
|
|
Sales of minerals in place
|
(7
|
)
|
|
(250
|
)
|
|
(10,287
|
)
|
|
(1,972
|
)
|
Production
|
(8,045
|
)
|
|
(211
|
)
|
|
(9,589
|
)
|
|
(9,855
|
)
|
End of year
|
114,765
|
|
|
1,147
|
|
|
160,849
|
|
|
142,720
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
||||
Beginning of year
|
68,490
|
|
|
1,271
|
|
|
100,384
|
|
|
86,492
|
|
End of year
|
73,203
|
|
|
1,047
|
|
|
76,331
|
|
|
86,971
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
||||
Beginning of year
|
32,106
|
|
|
—
|
|
|
136,720
|
|
|
54,893
|
|
End of year
|
41,562
|
|
|
100
|
|
|
84,518
|
|
|
55,749
|
|
|
Year Ended December 31, 2017
|
||||||||||
|
Oil
MBbls |
|
NGLs
MBbls |
|
Natural Gas MMcf
|
|
Total
MBoe |
||||
Total proved reserves:
|
|
|
|
|
|
|
|
||||
Beginning of year (Predecessor)
|
55,876
|
|
|
15,078
|
|
|
372,760
|
|
|
133,080
|
|
Revisions of previous estimates
|
9,089
|
|
|
431
|
|
|
32,144
|
|
|
14,878
|
|
Sales of proved reserves in place
|
(13
|
)
|
|
(13,329
|
)
|
|
(285,168
|
)
|
|
(60,870
|
)
|
Purchase of proved reserves in place
|
24,332
|
|
|
—
|
|
|
—
|
|
|
24,332
|
|
Extensions and discoveries
|
18,783
|
|
|
—
|
|
|
136,719
|
|
|
41,570
|
|
Production
|
(7,471
|
)
|
|
(909
|
)
|
|
(19,351
|
)
|
|
(11,605
|
)
|
End of year
|
100,596
|
|
|
1,271
|
|
|
237,104
|
|
|
141,385
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
||||
Beginning of year (Predecessor)
|
55,422
|
|
|
15,078
|
|
|
372,760
|
|
|
132,626
|
|
End of year
|
68,490
|
|
|
1,271
|
|
|
100,384
|
|
|
86,492
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
||||
Beginning of year (Predecessor)
|
454
|
|
|
—
|
|
|
—
|
|
|
454
|
|
End of year
|
32,106
|
|
|
—
|
|
|
136,720
|
|
|
54,893
|
|
|
Berry Corp. (Successor)
|
||||||||||
|
December 31, 2019
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||
|
(in thousands, except for prices)
|
||||||||||
Future cash inflows
|
$
|
7,788,647
|
|
|
$
|
8,119,309
|
|
|
$
|
5,580,448
|
|
Future production costs
|
(3,623,688
|
)
|
|
(3,357,149
|
)
|
|
(2,725,548
|
)
|
|||
Future development costs
|
(1,106,333
|
)
|
|
(884,055
|
)
|
|
(678,312
|
)
|
|||
Future income tax expenses(1)
|
(587,487
|
)
|
|
(757,470
|
)
|
|
(365,330
|
)
|
|||
Future net cash flows
|
2,471,139
|
|
|
3,120,635
|
|
|
1,811,258
|
|
|||
10% annual discount for estimated timing of cash flows
|
(1,005,002
|
)
|
|
(1,359,089
|
)
|
|
(833,910
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
1,466,137
|
|
|
$
|
1,761,546
|
|
|
$
|
977,348
|
|
Representative prices:(2)
|
|
|
|
|
|
||||||
Brent Oil (Bbl)
|
$
|
63.15
|
|
|
$
|
71.54
|
|
|
$
|
54.42
|
|
Henry Hub Natural gas (MMBtu)
|
$
|
2.62
|
|
|
$
|
3.10
|
|
|
$
|
2.98
|
|
(1)
|
Future income tax expenses are based on current statutory rates, adjusted for the tax basis of oil and gas properties and applicable tax credits, deductions and allowances.
|
(2)
|
In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.
|
|
Berry Corp. (Successor)
|
||||||||||
|
December 31, 2019
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||
|
(in thousands)
|
||||||||||
Standardized measure—beginning of year
|
$
|
1,761,546
|
|
|
$
|
977,348
|
|
|
$
|
596,222
|
|
Net change in sales and transfer prices and production costs related to future production
|
(309,347
|
)
|
|
818,705
|
|
|
224,064
|
|
|||
Changes in estimated future development costs
|
(120,688
|
)
|
|
35,313
|
|
|
6,399
|
|
|||
Sales and transfers of oil, natural gas and NGLs produced during the period
|
(300,261
|
)
|
|
(321,148
|
)
|
|
(189,355
|
)
|
|||
Net change due to extensions, discoveries and improved recovery
|
180,825
|
|
|
363,450
|
|
|
157,717
|
|
|||
Purchase of minerals in place
|
2,649
|
|
|
5,240
|
|
|
317,616
|
|
|||
Sales of minerals in place
|
—
|
|
|
(5,593
|
)
|
|
(141,998
|
)
|
|||
Net change due to revisions in quantity estimates
|
(124,110
|
)
|
|
(175,947
|
)
|
|
124,609
|
|
|||
Previously estimated development costs incurred during the period
|
116,921
|
|
|
78,803
|
|
|
6,913
|
|
|||
Accretion of discount
|
215,153
|
|
|
111,416
|
|
|
59,622
|
|
|||
Changes in production rates and other
|
(5,939
|
)
|
|
127,135
|
|
|
(47,651
|
)
|
|||
Net change in income taxes
|
49,388
|
|
|
(253,176
|
)
|
|
(136,810
|
)
|
|||
Net increase (decrease)
|
(295,409
|
)
|
|
784,198
|
|
|
381,126
|
|
|||
Standardized measure—end of year
|
$
|
1,466,137
|
|
|
$
|
1,761,546
|
|
|
$
|
977,348
|
|
|
Berry Corp.
(Successor)
|
|
|
Berry LLC (Predecessor)
|
||||||||||||
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
Ten Months Ended December 31, 2017
|
|
|
Two Months Ended February 28, 2017
|
||||||||
Weighted-average realized prices:
|
|
|
|
|
|
|
|
|
||||||||
Oil without hedges (Bbl)
|
$
|
58.93
|
|
|
$
|
64.76
|
|
|
$
|
48.05
|
|
|
|
$
|
46.94
|
|
Natural gas (Mcf)
|
$
|
2.66
|
|
|
$
|
2.74
|
|
|
$
|
2.70
|
|
|
|
$
|
3.42
|
|
NGLs (Bbl)
|
$
|
17.02
|
|
|
$
|
26.74
|
|
|
$
|
22.23
|
|
|
|
$
|
18.20
|
|
|
|
|
|
|
|
|
|
|
||||||||
Production costs (per Boe):
|
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
$
|
20.42
|
|
|
$
|
19.16
|
|
|
$
|
15.84
|
|
|
|
$
|
13.06
|
|
•
|
The initial term of the Amended Agreement is three years, with automatic one-year extensions on each anniversary of the effective date, unless either party gives notice of non-renewal at least 60 days prior to the such anniversary date.
|
•
|
Mr. Smith’s base salary remains $650,000, which will be reviewed at least annually by the Board of Directors (or a committee thereof) and may be increased, but not decreased without Mr. Smith’s consent; provided, however, that Mr. Smith’s consent will not be required on a determination by the Board (or a committee thereof) that a decrease of no more than 10% is necessary and appropriate, and such decreases are part of similar reductions applicable to the Company’s similarly situated executive officers.
|
•
|
Mr. Smith is eligible to receive an annual equity award in an amount and under terms to be determined in the sole discretion of the Board of Directors (or a committee thereof). It is contemplated that the amount will be equal to but not less than three times the sum of Mr. Smith’s base salary and target bonus amount for the applicable year, but ultimately subject to determination in the sole discretion of the Board of Directors (or a committee thereof).
|
•
|
Mr. Smith must give 90 days’ notice in the event he voluntarily resigns from employment.
|
•
|
Upon a termination of Mr. Smith’s employment under certain circumstances, including termination without Cause (as defined in the Amended Agreement) by the Company, his voluntary resignation on the basis of Good Reason (as defined in the Amended Agreement), his death or disability, he is eligible to receive, among other payments and benefits, severance in an amount equal to two times (or, if such termination occurs within 12 months following a Sale of Berry (as defined in the Amended Agreement), three times) the sum of Mr. Smith’s base salary and target annual bonus amount for the year of termination, plus an additional cash payment to cover health insurance premiums in certain circumstances.
|
Exhibit Number
|
|
Description
|
|
|
|
2.1
|
|
|
3.1*
|
|
|
3.2*
|
|
|
3.3
|
|
|
3.4
|
|
|
4.1
|
|
|
4.2
|
|
|
4.3
|
|
|
4.4*
|
|
|
10.1
|
|
|
10.2
|
|
|
10.3
|
|
|
10.4
|
|
|
10.5†
|
|
|
10.6†
|
|
|
10.7†
|
|
|
10.8†
|
|
|
10.9†
|
|
|
10.10†
|
|
Exhibit Number
|
|
Description
|
10.11†*
|
|
|
10.12†*
|
|
|
10.13†*
|
|
|
10.14†
|
|
|
10.15†
|
|
|
10.16†
|
|
|
10.17†
|
|
|
10.18†
|
|
|
10.19†
|
|
|
10.20†
|
|
|
10.21†
|
|
|
10.22†
|
|
|
10.23†
|
|
|
10.24†
|
|
|
10.25†
|
|
|
10.26†
|
|
|
10.27
|
|
|
10.28
|
|
Exhibit Number
|
|
Description
|
10.29
|
|
|
10.30
|
|
|
10.31
|
|
|
10.32
|
|
|
10.33
|
|
|
10.34
|
|
|
21.1*
|
|
|
23.1*
|
|
|
23.2*
|
|
|
31.1*
|
|
|
31.2*
|
|
|
32.1*
|
|
|
99.1*
|
|
|
101.INS*
|
|
XBRL Instance Document
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
101.LAB*
|
|
XBRL Taxonomy Extension Label Linkbase Data Document
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
(*)
|
Filed herewith.
|
|
|
BERRY CORPORATION (bry)
|
|
|
|
Date:
|
February 27, 2020
|
/s/ A. T. Smith
|
|
|
A. T. “Trem” Smith
|
|
|
President and Chief Executive Officer
|
Date
|
Signature
|
Title
|
|
|
|
February 27, 2020
|
/s/ A. T. Smith
|
President and Chief Executive Officer, and Director
|
|
A. T. “Trem” Smith
|
(Principal Executive Officer)
|
|
|
|
February 27, 2020
|
/s/ Cary Baetz
|
Executive Vice President and Chief
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Cary Baetz
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Financial Officer, and Director
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(Principal Financial Officer)
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February 27, 2020
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/s/ M. S. Helm
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Chief Accounting Officer
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Michael S. Helm
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(Principal Accounting Officer)
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February 27, 2020
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/s/ E. J. Voiland
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Director
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Eugene J. Voiland
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February 27, 2020
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/s/ Brent S. Buckley
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Director
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Brent S. Buckley
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February 27, 2020
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/s/ C K Potter
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Director
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C. Kent Potter
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February 27, 2020
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/s/ Anne L. Mariucci
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Director
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Anne L. Mariucci
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February 27, 2020
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/s/ Donald L. Paul
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Director
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Donald L. Paul
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•
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Advance notice is required for stockholders to nominate directors or to submit proposals for consideration at meetings of stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive
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•
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Directors may be removed from office, either for or without cause, by the affirmative vote of the holders of a majority of the voting power of the then-outstanding shares of capital stock entitled to vote generally in the election of directors).
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•
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Stockholders may call a special meeting only upon request of at least 25% of the voting power of the shares entitled to vote in the election of directors.
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•
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any derivative action or proceeding brought on our behalf;
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•
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any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders;
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•
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any action asserting a claim against us or our directors, officers or employees arising pursuant to any provision of the DGCL, our Certificate of Incorporation or Bylaws; or
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•
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any action asserting a claim against us or our directors, officers or employees that is governed by the internal affairs doctrine;
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1.
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Release.
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3.
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Miscellaneous.
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BERRY PETROLEUM COMPANY, LLC
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By:___________________________________
Name: [NAME OF AUTHORIZED OFFICER]
Title: [TITLE OF AUTHORIZED OFFICER]
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DANIELLE HUNTER
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Signature:____________________________
Print Name: __________________________
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1.
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Release.
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3.
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Miscellaneous.
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BERRY PETROLEUM COMPANY, LLC
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By:___________________________________
Name: [NAME OF AUTHORIZED OFFICER]
Title: [TITLE OF AUTHORIZED OFFICER]
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MEGAN SILVA
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Signature:____________________________
Print Name: __________________________
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(c)
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Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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(d)
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Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
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The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
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(a)
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
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(b)
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
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Date:
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February 27, 2020
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/s/ A. T. Smith
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A. T. “Trem” Smith
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President and Chief Executive Officer
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(c)
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Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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(d)
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Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
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The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
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(a)
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
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(b)
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
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Date:
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February 27, 2020
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/s/ Cary Baetz
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Cary Baetz
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Executive Vice President and
Chief Financial Officer
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1.
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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2.
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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Date:
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February 27, 2020
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/s/ A. T. Smith
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A. T. “Trem” Smith
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President and Chief Executive Officer
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Date:
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February 27, 2020
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/s/ Cary Baetz
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Cary Baetz
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Executive Vice President and
Chief Financial Officer
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Estimated by DeGolyer and MacNaughton
Net Proved Reserves
as of
December 31, 2019
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||||||
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Oil and Condensate
(Mbbl)
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NGL
(Mbbl)
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Sales
Gas
(MMcf)
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Oil
Equivalent (Mboe)
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Proved Developed
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74,102
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1,054
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39,063
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81,666
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Proved Undeveloped
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55,671
|
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127
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5,752
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56,757
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Total Proved
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129,773
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1,181
|
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44,815
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138,423
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Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.
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1.
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That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Berry Petroleum Company, LLC dated January 31, 2020, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.
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2.
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That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations.
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