VITAL ENERGY, INC. The following discussion and analysis of our financial condition and results of operations is for the three and six months endedJune 30, 2020 and 2019, and should be read in conjunction with our unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report as well as our audited consolidated financial statements and notes thereto included in our 2019 Annual Report. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please see "Cautionary Statement Regarding Forward-Looking Statements" and "Part II, Item 1A. Risk Factors." Except for purposes of the unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report, references in this Quarterly Report to "Laredo ," "we," "us," "our" or similar terms refer toLaredo , LMS and GCM collectively, unless the context otherwise indicates or requires. Unless otherwise specified, references to "average sales price" refer to average sales price excluding the effects of our derivative transactions. All amounts, dollars and percentages presented in this Quarterly Report are rounded and therefore approximate. Executive overview We are an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, primarily in thePermian Basin ofWest Texas . Since our inception, we have grown primarily through our drilling program, coupled with select strategic acquisitions and joint ventures. Our financial and operating performance included the following for the periods presented and corresponding changes: Three months ended June 30, 2020 compared to 2019 (in thousands) 2020 2019 Change (#) Change (%) Oil sales volumes (MBbl) 2,843 2,771 72 3 % Oil equivalents sales volumes (MBOE) 8,565 7,485 1,080 14 % Oil, NGL and natural gas sales(1)$ 94,143 $ 183,863 $ (89,720) (49) % Net income (loss)(2)$ (545,455) $ 173,382 $ (718,837) (415) %
Free Cash Flow (a non-GAAP financial measure)(3)
$ 39,973 $ (63,519) (159) % Adjusted EBITDA (a non-GAAP financial measure)(3)$ 132,837 $ 153,218 $ (20,381) (13) %
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(1)Our oil, NGL and natural gas sales decreased as a result of a 55% decrease in average sales price per BOE and were partially offset by a 14% increase in total volumes sold. (2)Our net loss for the three months endedJune 30, 2020 includes a non-cash full cost ceiling impairment of$406.4 million . (3)See page 54 for discussions regarding and calculations of these non-GAAP financial measures. 32
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Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change (#) Change (%)
Oil sales volumes (MBbl) 5,498 5,305 193 4 %
Oil equivalents sales volumes (MBOE) 16,439 14,260 2,179 15 %
Oil, NGL and natural gas sales(1) $ 230,028 $ 357,239 $ (127,211) (36) %
Net income (loss)(2) $ (470,809) $ 163,891 $ (634,700) (387) %
Free Cash Flow (a non-GAAP financial measure)(3)
$ (10,992) $ (70,077) (638) % Adjusted EBITDA (a non-GAAP financial measure)(3)$ 249,685 $ 276,124 $ (26,439) (10) %
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(1)Our oil, NGL and natural gas sales decreased as a result of a 44% decrease in average sales price per BOE and were partially offset by a 15% increase in total volumes sold. (2)Our net loss for the six months endedJune 30, 2020 includes a non-cash full cost ceiling impairment of$583.6 million . (3)See page 54 for discussions regarding and calculations of these non-GAAP financial measures. Recent developments Restatement of our unaudited consolidated financial statements for the quarter endedMarch 31, 2020 OnAugust 5, 2020 , we filed an amendment to our quarterly report to restate our unaudited consolidated financial statements for the quarter endedMarch 31, 2020 (the "Restated First Quarter Financials") to correct an error in the future production costs component of the estimated present value ("PV-10") of our reserves. The omitted costs caused an understatement of approximately$160 million of the full cost ceiling impairment expense and balances of accumulated depletion and impairment and accumulated deficit, and a corresponding overstatement of the same amount to both net income and the balance of our oil and natural gas properties for the first quarter of 2020. This error was identified in the course of preparing our unaudited consolidated financial statements for the quarter endedJune 30, 2020 . This error was isolated to our first-quarter estimate of the PV-10 of our reserves and had no impact on our prior financial statements, including the 2019 Annual Report. This Quarterly Report gives effect to the restated financial information for the quarter endedMarch 31, 2020 . In addition, we have received a waiver from the lenders under our Senior Secured Credit Facility in connection with the error. Reverse stock split OnJune 1, 2020 , we effected the previously announced 1-for-20 reverse stock split of our common stock and the related reduction of the number of authorized shares of common stock, which were previously approved by our stockholders at our 2020 annual meeting of stockholders. Our common stock began trading, on a split-adjusted basis and under our existing trading symbol, at the opening of trading onJune 2, 2020 . See Note 7.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of the reverse stock split. OnJuly 1, 2020 , we were notified that we were in compliance with theNew York Stock Exchange's continued listing criterion of a minimum share price of$1 over a 30 trading-day period. Organizational restructuring OnJune 17, 2020 , we announced organizational changes, including a workforce reduction of 22 individuals, which included a senior officer, that were implemented immediately, subject to certain administrative procedures. In light of the COVID-19 pandemic and lower oil prices, our board of directors continues to monitor and evaluate our business and strategy and to reduce costs and better position us for the future. In connection with the organizational changes, we announced the departure of our former Senior Vice President and Chief Financial Officer ("former CFO"), effective as ofJune 17, 2020 . Our former CFO's departure was not the result of any dispute or disagreement with us or our accounting practices or financial statements. We incurred$4.2 million of one-time organizational restructuring expenses during the three months endedJune 30, 2020 , comprised of compensation, tax, professional, outplacement and insurance-related expenses. See Note 18 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of the organizational restructuring. 33 -------------------------------------------------------------------------------- Table of Contents OnJune 17, 2020 , we announced that the board of directors appointedBryan J. Lemmerman as Senior Vice President-Chief Financial Officer and Assistant Secretary effective as ofJune 30, 2020 . COVID-19 InDecember 2019 , a highly transmissible and pathogenic strain of coronavirus surfaced inChina , which has and is continuing to spread throughout the world, including theU.S. OnJanuary 30, 2020 , theWorld Health Organization declared the outbreak of COVID-19 a "Public Health Emergency of International Concern," and onMarch 11, 2020 , theWorld Health Organization characterized the outbreak as a "pandemic". Federal, state and local authorities have recommended stay-at-home orders and social distancing guidelines forU.S. residents and to avoid all unnecessary travel for any reason including non-essential jobs for an indeterminate amount of time until the spread of COVID-19 declines to acceptable lower levels. Such actions have resulted in a swift and unprecedented reduction in international andU.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused significant volatility and disruption of the financial markets. We are not able to predict the duration or ultimate impact that COVID-19 will have on our business, financial condition and results of operations. We are responding to these current events with thoughtful planning and are committed to maintaining safe and reliable operations. The health and safety of our employees, suppliers and customers remain a top priority. To protect the health and safety of our employees and business partners, we have instituted policies to promote social distancing, both in the office and at field locations. Additionally, the majority of our non-field based employees have successfully transitioned to working from home. We are closely monitoring local infection rates and instituting the appropriateCenters for Disease Control and Prevention guidelines to determine return-to-work policies while minimizing interruptions to our operations. We do not believe that these measures have had a material effect on our workforce productivity. OnMarch 27, 2020 , the CARES Act was enacted in response to the COVID-19 pandemic. It included provisions intended to provide relief to individuals and businesses in the form of loans and grants, and tax changes, among other provisions. At this time, we have not sought relief in the form of loans or grants from the CARES Act; however, we have benefited from the provision where the AMT credit carryforwards do not expire and are fully refundable. Volatility in Commodity Prices In earlyMarch 2020 , concurrent with the spread of COVID-19 to theU.S. and just prior to the government actions mentioned above, members of OPEC+ proposed production cuts in an attempt to stabilize the oil market. However, OPEC+ failed to reach an agreement and some producers instead announced planned production increases, after which oil prices declined sharply. Bymid-March 2020 , WTI oil prices had declined to less than$25 per barrel, the lowest price since 2002. Although OPEC+ subsequently reached agreement inApril 2020 on production cuts that went into effect inMay 2020 , oil prices continued to decline following announcement of the agreement. Further, producers in theU.S. and globally have not reduced oil production at a rate sufficient to match the sharp slowdown in economic activity caused by measures to control the spread of COVID-19, resulting in an oversupply of oil that recently caused WTI oil prices per barrel to fall to-$37 onApril 20th . Since theApril 20th low, WTI oil prices have rebounded to around$40 , trading in a range of$40 to$42 in the month of July. We maintain an active, multi-year commodity derivatives strategy to minimize commodity price volatility and support cash flows needed for operations. For July throughDecember 2020 , we currently have oil derivatives in place for 3.6 million barrels swapped at a weighted-average price of$59.50 WTI per barrel and 1.2 million barrels swapped at a weighted-average price of$63.07 Brent per barrel. We entered into derivatives subsequent toJune 30, 2020 for both 2021 and 2022. For 2021, we currently have oil derivatives in place for 7.4 million barrels at a weighted-average floor price of$51.11 Brent per barrel. For 2022, we currently have oil derivatives in place for 2.9 million barrels at a weighted-average floor price of$46.40 Brent per barrel. With oil prices moving to above$40 late in the second quarter of 2020, and our execution of additional oil commodity hedges for 2021 and 2022 subsequent toJune 30, 2020 , we expect to add completions activity in the last four months of 2020 and drilling activity beginning in January of 2021. We currently expect capital expenditures for 2020 to be approximately$340 million to$350 million . We will continue to monitor commodity prices and service costs and adjust activity levels in order to proactively manage our cash flows and preserve liquidity. We will continue to utilize this slowdown as an opportunity to improve on our strong operations performance and to continue to reduce expenses to the lowest and most efficient cost structure possible. 34 -------------------------------------------------------------------------------- Table of Contents Senior Secured Credit Facility OnApril 30, 2020 , as a result of the semi-annual redetermination, we entered into the fourth amendment to our Senior Secured Credit Facility pursuant to which the borrowing base and aggregate elected commitment were reduced to$725.0 million each. Other than the decrease in borrowing base and aggregate elected commitment, among the more significant changes are: (i) margin applied to both Eurodollar and Adjusted Base Rate Loans and the fees charged in connection with letters of credit were increased by 0.500%, in each case, at all levels of Borrowing Base utilization; (ii) the aggregate amount of Asset Dispositions that may occur since the Determination Date of the Borrowing Base then in effect without triggering an automatic reduction of the Borrowing Base was reduced from 10% to 5% of the Borrowing Base then in effect; (iii) the definition of Permitted Investments was modified to eliminate a safe harbor for investments in partnerships and joint ventures and the general "other" safe harbor; and (iv) the definition ofPermitted Investment and covenants limiting Distributions and Redemption of Senior Notes were modified such that Investment, Distributions and Redemptions of Senior Notes remain permitted, in each case, so long as immediately after giving effect to such Investment, Distribution or Redemption (a) the amount of Distributions, Investments and Redemptions from and afterApril 1, 2020 is not greater than$100 million , (b) no Default or Event of Default exists, (c) undrawn Commitments are greater than or equal to 35% of Total Commitments, (d) the pro forma ratio of Consolidated Current Assets to Consolidated Current Liabilities is not less than 1.00 to 1.00, and (e) the pro forma Consolidated Total Leverage Ratio is not greater than 2.50 to 1.00. All capitalized terms above have the meanings ascribed to them in the Fourth Amendment or the Senior Secured Credit Facility, as applicable. The financial covenant requiring a Consolidated Total Leverage Ratio of not greater than 4.25 to 1.00 at each fiscal quarter end for the preceding four fiscal quarters remains unchanged. Pricing and reserves Our results of operations are heavily influenced by oil, NGL and natural gas prices, which have experienced significant declines that continue in third-quarter 2020. Oil, NGL and natural gas price fluctuations are currently impacted by the COVID-19 pandemic and policies of OPEC+, which have generally increased supply, decreased demand, made more volatile economic and market conditions, caused transportation and storage constraints and led to a variety of additional issues on both a regional and global basis. Historically, commodity prices have experienced significant fluctuations; however, the volatility in the prices has substantially increased as a result of the recent world developments in 2020. The duration of such developments may affect the economic viability of, and our ability to fund our drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves. We have entered into a number of commodity derivative contracts that have enabled us to offset a portion of the changes in our cash flow caused by fluctuations in price and basis differentials for our sales of oil, NGL and natural gas, as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk." See Notes 9, 10.a and 19.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our commodity derivatives, including those entered into subsequent toJune 30, 2020 . Our reserves as ofJune 30, 2020 andDecember 31, 2019 are reported in three streams: oil, NGL and natural gas. As discussed in Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report, the Realized Prices utilized to value our proved reserves as ofJune 30, 2020 andJune 30, 2019 , are as follows: June 30, 2020 June 30, 2019 Realized Prices: Oil ($/Bbl)$ 44.97 $ 55.69 NGL ($/Bbl)$ 7.66 $ 18.64 Natural gas ($/Mcf)$ 0.53 $ 0.70 The Realized Prices used to estimate proved reserves do not include derivative transactions. The unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling as ofMarch 31, 2020 andJune 30, 2020 and, as such, we recorded first and second-quarter non-cash full cost ceiling impairments of$177.2 million and$406.4 million , respectively. No such impairments were recorded during the six months endedJune 30, 2019 . As more specifically addressed in "Low commodity price potential impact on our third-quarter 2020 and Remaining Year 2020 full cost ceiling impairment tests" below, if prices remain at or below the current levels, subject to numerous factors and inherent limitations, and all other factors remain constant, we could incur additional significant non-cash full cost ceiling impairments in the third quarter of 2020 and Remaining Year 2020 (defined below), which will have an adverse effect on our results of operations. See Note 4 35 -------------------------------------------------------------------------------- Table of Contents to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our full cost method of accounting. Horizontal drilling of unconventional wells using enhanced completions techniques, including, but not limited to, hydraulic fracturing, is a relatively new process and, as such, forecasting the long-term production of such wells is inherently uncertain and subject to varying interpretations. As we receive and process geological and production data from these wells over time, we analyze such data to confirm whether previous assumptions regarding original forecasted production, inventory and reserves continue to appear accurate or require modification. While all production forecasts have elements of uncertainty over the life of the related wells, we have seen indications that the oil decline rates of tightly spaced wells may be steeper than originally anticipated. In 2019, we began drilling and completing wells at wider spacing to mitigate this effect in established acreage. Initial production results, production decline rates, well density, completions design and operating method are examples of the numerous uncertainties and variables inherent in the estimation of proved reserves in future periods. The quantity of proved reserves is one of the many variables inherent in the calculation of depletion. The following tables present our depletion expense for our evaluated oil and natural gas properties per BOE sold for the periods presented and corresponding changes: Three months ended June 30, 2020 compared to 2019 2020 2019 Change ($) Change (%) Depletion expense per BOE sold$ 7.39 $ 8.27 $ (0.88) (11) % Six months ended June 30, 2020 compared to 2019 2020 2019 Change ($) Change (%) Depletion expense per BOE sold$ 7.36 $ 8.51 $ (1.15) (14) % Low commodity price potential impact on our third-quarter 2020 and Remaining Year 2020 full cost ceiling impairment tests We use the full cost method of accounting for our oil and natural gas properties, with the full cost ceiling, as defined by theSEC , based principally on the estimated future net revenues from our proved oil, NGL and natural gas reserves, which exclude the effect of our commodity derivative transactions, discounted at 10% under requiredSEC guidelines for pricing methodology. We review the carrying value of our oil and natural gas properties under the full cost accounting rules of theSEC on a quarterly basis. In the event the unamortized cost, or net book value, of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, the excess is expensed in the period such excess occurs. Once incurred, a write-down of evaluated oil and natural gas properties is not reversible. If prices remain at or below the current levels, subject to numerous factors and inherent limitations, some of which are discussed below, and all other factors remain constant, we could incur substantial non-cash full cost ceiling impairments in third-quarter 2020 and Remaining Year 2020, which will have an adverse effect on our statement of operations. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. In addition to unknown future commodity prices, other uncertainties include, but are not limited to (i) changes in drilling and completions costs, (ii) changes in oilfield service costs, (iii) production results, (iv) our ability, in a low price environment, to strategically drill the most economic locations in our multi-level horizontal targets, (v) government imposed curtailment of production, (vi) the potential to shut-in a portion or all of our wells, (vii) income tax impacts, (viii) potential recognition of additional proved undeveloped reserves, (ix) any potential value added to our proved reserves when testing recoverability from drilling unbooked locations, (x) revisions to production curves based on additional data and (xi) the inherent significant volatility in the commodity prices for oil, NGL and natural gas. Each of the above factors is evaluated on a quarterly basis and if there is a material change in any factor it is incorporated into our reserves estimation utilized in our quarterly accounting estimates. We use our reserve estimates to evaluate, also on a quarterly basis, the reasonableness of our resource development plans for our reported proved reserves. Changes in circumstance, including commodity pricing, economic factors and the other uncertainties described above may lead to changes in our development plans. 36 -------------------------------------------------------------------------------- Table of Contents Set forth below are calculations of potential future impairments of our evaluated oil and natural gas properties for the third-quarter 2020 and for the period ofJuly 1 to December 31, 2020 ("Remaining Year 2020"). Such implied impairments should not be interpreted to be indicative of our development plan or of our actual future results. Each of the uncertainties noted above has been evaluated for material known trends to be potentially included in the estimation of possible third-quarter 2020 and Remaining Year 2020 effects. Based on such review, we determined that the impact of decreased commodity prices is the only significant known variable necessary in calculating the following scenario. Our hypothetical third-quarter 2020 full cost ceiling calculation has been prepared by substituting (i)$41.29 per Bbl for oil, (ii)$7.34 per Bbl for NGL and (iii)$0.70 per Mcf for natural gas (collectively, the "Pro Forma Third-Quarter Prices") for the respective Realized Prices as ofJune 30, 2020 . All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of low commodity prices on the third-quarter 2020 Realized Prices that will be utilized in our full cost ceiling calculation. The Pro Forma Third-Quarter Prices use a slightly modified Realized Price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for oil, NGL and natural gas for the 10 months endedJuly 1, 2020 and holding theJuly 1, 2020 prices constant for the remaining eleventh and twelfth months of the calculation. Based solely on the substitution of the Pro Forma Third-Quarter Prices into ourJune 30, 2020 proved reserve estimates, the implied third-quarter 2020 impairment would be$100 million . Our hypothetical Remaining Year 2020 full cost ceiling calculation has been prepared by substituting (i)$39.79 per Bbl for oil, (ii)$6.93 per Bbl for NGL and (iii)$0.80 per Mcf for natural gas (collectively, the "Pro Forma Remaining Year Prices") for the respective Realized Prices. All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of low commodity prices on the Remaining Year 2020 Realized Prices that will be utilized in our full cost ceiling calculation. The Pro Forma Remaining Year Prices use a slightly modified Realized Price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for oil, NGL and natural gas for the seven months endedJuly 1, 2020 and using strip pricing as ofJuly 20, 2020 for the remaining five months. Based solely on the substitution of the Pro Forma Remaining Year Prices into ourJune 30, 2020 proved reserve estimates, the implied Remaining Year 2020 impairment would be$145 million . We believe that substituting these prices into ourJune 30, 2020 proved reserve estimates may help provide users with an understanding of the potential impact on our third-quarter 2020 and Remaining Year 2020 full cost ceiling tests. See Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for prices used to value our reserves and additional discussion of our full cost impairments for the three and six months endedJune 30, 2020 . Core area of operations The oil and liquids-richPermian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. As ofJune 30, 2020 , we had assembled 130,993 net acres in thePermian Basin . Results of operations Revenues Sources of our revenue Our revenues are derived from the sale of produced oil, NGL and natural gas, the sale of purchased oil and providing midstream services to third parties, all within the continentalUnited States and do not include the effects of derivatives. Our oil, NGL and natural gas revenues may vary significantly from period to period as a result of changes in volumes of production, pricing differentials and/or changes in commodity prices. Our sales of purchased oil revenue may vary due to changes in oil prices, pricing differentials and the amount of volumes purchased. Our midstream service revenues may fluctuate and vary due to oil throughput fees and the level of services provided to third parties for (i) integrated oil and natural gas gathering and transportation systems and related facilities, (ii) natural gas lift, fuel for drilling and completions activities and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure. See Notes 2.o and 13.b to our consolidated financial statements in our 2019 Annual Report for additional information regarding our revenue recognition policies. 37 -------------------------------------------------------------------------------- Table of Contents The following tables present our sources of revenue as a percentage of total revenues for the periods presented and corresponding changes: Three months ended June 30, 2020 compared to 2019 2020 2019 Change (#) Change (%) Oil sales 63 % 74 % (11) % (15) % NGL sales 12 % 10 % 2 % 20 % Natural gas sales 10 % 1 % 9 % 900 % Midstream service revenues 2 % 1 % 1 % 100 % Sales of purchased oil 13 % 14 % (1) % (7) % Total 100 % 100 % Six months ended June 30, 2020 compared to 2019 2020 2019 Change (#) Change (%) Oil sales 60 % 68 % (8) % (12) % NGL sales 8 % 13 % (5) % (38) % Natural gas sales 4 % 3 % 1 % 33 % Midstream service revenues 2 % 1 % 1 % 100 % Sales of purchased oil 26 % 15 % 11 % 73 % Total 100 % 100 % 38
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Oil, NGL and natural gas sales volumes, revenues and prices
The following tables present information regarding our oil, NGL and natural gas
sales volumes, sales revenues and average sales prices for the periods presented
and corresponding changes:
Three months ended June 30, 2020
compared to 2019
2020 2019 Change (#) Change (%)
Sales volumes:
Oil (MBbl) 2,843 2,771 72 3 %
NGL (MBbl) 2,752 2,200 552 25 %
Natural gas (MMcf) 17,817 15,092 2,725 18 %
Oil equivalents (MBOE)(1)(2) 8,565 7,485 1,080 14 %
Average daily oil equivalent sales volumes (BOE/D)(2) 94,117 82,259 11,858 14 %
Average daily oil sales volumes (Bbl/D)(2) 31,241 30,447 794 3 %
Sales revenues (in thousands):
Oil $ 70,105 $ 160,030 $ (89,925) (56) %
NGL 13,228 22,197 (8,969) (40) %
Natural gas 10,810 1,636 9,174 561 %
Total oil, NGL and natural gas sales revenues $ 94,143 $ 183,863 $ (89,720) (49) %
Average sales prices(2):
Oil ($/Bbl)(3) $ 24.66 $ 57.76 $ (33.10) (57) %
NGL ($/Bbl)(3) $ 4.81 $ 10.09 $ (5.28) (52) %
Natural gas ($/Mcf)(3) $ 0.61 $ 0.11 $ 0.50 455 %
Average sales price ($/BOE)(3) $ 10.99 $ 24.56 $ (13.57) (55) %
Oil, with commodity derivatives ($/Bbl)(4) $ 50.46 $ 56.65 $ (6.19) (11) %
NGL, with commodity derivatives ($/Bbl)(4) $ 7.60 $ 12.82 $ (5.22) (41) %
Natural gas, with commodity derivatives ($/Mcf)(4) $ 0.91 $ 1.17 $ (0.26) (22) %
Average sales price, with commodity derivatives ($/BOE)(4) $ 21.09 $ 27.09 $ (6.00) (22) %
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(1)BOE is calculated using a conversion rate of six Mcf per one Bbl. (2)The numbers presented in the three months endedJune 30, 2020 and 2019 columns are based on actual amounts and are not calculated using the rounded numbers presented in the table above or the table below. (3)Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. (4)Price reflects the after-effects of our commodity derivative transactions on our average sales prices. Our calculation of such after-effects includes settlements of matured commodity derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to commodity derivatives that settled during the respective periods. 39
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Six months ended June 30, 2020 compared to 2019
2020 2019 Change (#) Change (%)
Sales volumes:
Oil (MBbl) 5,498 5,305 193 4 %
NGL (MBbl) 5,219 4,299 920 21 %
Natural gas (MMcf) 34,329 27,941 6,388 23 %
Oil equivalents (MBOE)(1)(2) 16,439 14,260 2,179 15 %
Average daily oil equivalent sales volumes (BOE/D)(2) 90,324 78,787 11,537 15 %
Average daily oil sales volumes (Bbl/D)(2) 30,209 29,308 901 3 %
Sales revenues (in thousands):
Oil $ 190,083 $ 289,201 $ (99,118) (34) %
NGL 24,786 54,432 (29,646) (54) %
Natural gas 15,159 13,606 1,553 11 %
Total oil, NGL and natural gas sales revenues $ 230,028 $ 357,239 $ (127,211) (36) %
Average sales prices(2):
Oil ($/Bbl)(3) $ 34.57 $ 54.52 $ (19.95) (37) %
NGL ($/Bbl)(3) $ 4.75 $ 12.66 $ (7.91) (62) %
Natural gas ($/Mcf)(3) $ 0.44 $ 0.49 $ (0.05) (10) %
Average sales price ($/BOE)(3) $ 13.99 $ 25.05 $ (11.06) (44) %
Oil, with commodity derivatives ($/Bbl)(4) $ 53.42 $ 52.36 $ 1.06 2 %
NGL, with commodity derivatives ($/Bbl)(4) $ 7.24 $ 14.04 $ (6.80) (48) %
Natural gas, with commodity derivatives ($/Mcf)(4) $ 0.93 $ 1.14 $ (0.21) (18) %
Average sales price, with commodity derivatives ($/BOE)(4) $ 22.10 $ 25.94 $ (3.84) (15) %
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(1)BOE is calculated using a conversion rate of six Mcf per one Bbl. (2)The numbers presented in the six months endedJune 30, 2020 and 2019 columns are based on actual amounts and are not calculated using the rounded numbers presented in the table above or the table below. (3)Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. (4)Price reflects the after-effects of our commodity derivative transactions on our average sales prices. Our calculation of such after-effects includes settlements of matured commodity derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to commodity derivatives that settled during the respective periods. 40 -------------------------------------------------------------------------------- Table of Contents The following tables present settlements received (paid) for matured commodity derivatives and premiums paid previously or upon settlement attributable to commodity derivatives that matured during the periods utilized in our calculation of the average sales prices, with commodity derivatives, for the periods presented and corresponding changes: Three months ended June 30, 2020 compared to 2019 (in thousands) 2020 2019 Change ($) Change (%) Settlements received for matured commodity derivatives: Oil$ 73,739 $ 1,481 $ 72,258 4,879 % NGL 7,680 5,998 1,682 28 % Natural gas 5,432 16,001 (10,569) (66) % Total$ 86,851 $ 23,480 $ 63,371 270 % Premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period: Oil$ (400) $ (4,541) $ 4,141 91 % Six months ended June 30, 2020 compared to 2019 (in thousands) 2020 2019 Change ($) Change (%) Settlements received (paid) for matured commodity derivatives: Oil$ 104,886 $ (614) $ 105,500 17,182 % NGL 13,017 5,941 7,076 119 % Natural gas 16,671 18,255 (1,584) (9) % Total$ 134,574 $ 23,582 $ 110,992 471 % Premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period: Oil$ (1,277) $ (10,841) $ 9,564 88 % Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three and six months endedJune 30, 2020 and 2019: (in thousands) Oil NGL Natural gas Total 2019 Revenues$ 160,030 $ 22,197 $ 1,636 $ 183,863 Effect of changes in average sales prices (94,095) (14,545) 8,879 (99,761) Effect of changes in sales volumes 4,170 5,576 295 10,041 2020 Revenues$ 70,105 $ 13,228 $ 10,810 $ 94,143 Change ($)$ (89,925) $ (8,969) $ 9,174 $ (89,720) Change (%) (56) % (40) % 561 % (49) % (in thousands) Oil NGL Natural gas Total 2019 Revenues$ 289,201 $
54,432
(1,558) (152,514)
Effect of changes in sales volumes 10,537 11,655 3,111 25,303
2020 Revenues $ 190,083 $ 24,786 $ 15,159 $ 230,028
Change ($) $ (99,118) $ (29,646) $ 1,553 $ (127,211)
Change (%) (34) % (54) % 11 % (36) %
Beginning in March 2020 , we experienced significant decreases in oil, NGL and
natural gas sales prices related to the OPEC+ caused price collapse and COVID-19
caused demand reduction. Oil sales prices have stabilized and recovered to some
degree at the end of the second quarter of 2020, compared to the lows at the
beginning of the second quarter, but are continuing to exhibit high volatility.
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Oil sales revenue. Our oil sales revenue is a function of oil production volumes
sold and average oil sales prices received for those volumes. The decrease in
oil sales revenue for the three months ended June 30, 2020 , compared to the same
period in 2019 is due to a 57% decrease in average oil sales prices and was
partially offset by a 3% increase in oil sales volumes. The decrease in oil
sales revenue for the six months ended June 30, 2020 , compared to the same
period in 2019 is due to a 37% decrease in average oil sales prices and was
partially offset by a 4% increase in oil sales volumes.
NGL sales revenue. Our NGL sales revenue is a function of NGL production volumes
sold and average NGL sales prices received for those volumes. The decrease in
NGL sales revenue for the three months ended June 30, 2020 , compared to the same
period in 2019 is due to a 52% decrease in average NGL sales prices and was
partially offset by a 25% increase in NGL sales volumes. The decrease in NGL
sales revenue for the six months ended June 30, 2020 , compared to the same
period in 2019 is due to a 62% decrease in average NGL sales prices and was
partially offset by a 21% increase in NGL sales volumes.
Natural gas sales revenue. Our natural gas sales revenue is a function of
natural gas production volumes sold and average natural gas sales prices
received for those volumes. The increase in natural gas sales revenue for the
three months ended June 30, 2020 , compared to the same period in 2019 is due to
a 455% increase in average natural gas sales prices and an 18% increase in
natural gas sales volumes. The increase in natural gas sales revenue for the six
months ended June 30, 2020 , compared to the same period in 2019 is due to a 23%
increase in natural gas sales volumes and was partially offset by a 10% decrease
in average natural gas sales prices.
The following tables present midstream service and sales of purchased oil
revenues for the periods presented and corresponding changes:
Three months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Midstream service revenues $ 2,281 $ 2,610 $ (329) (13) %
Sales of purchased oil $ 14,164 $ 30,170 $ (16,006) (53) %
Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Midstream service revenues $ 4,964 $ 5,493 $ (529) (10) %
Sales of purchased oil $ 80,588 $ 62,858 $ 17,730 28 %
Midstream service revenues. Our midstream service revenues decreased for the
three and six months ended June 30, 2020 compared to the same periods in 2019.
These revenues fluctuate and will vary due to oil throughput fees and the level
of services provided to third parties.
Sales of purchased oil. Sales of purchased oil revenues are a function of the
volumes and prices of purchased oil sold to customers and are offset by the
volumes and costs of purchased oil. We are a firm shipper on both the Bridgetex
and Gray Oak pipelines, the latter of which we began shipment on during
fourth-quarter 2019, and we utilize purchased oil to fulfill portions of our
commitments. We anticipate continuing this practice in the future.
We enter into purchase transactions with third parties and separate sale
transactions. These transactions are presented on a gross basis as we act as the
principal in the transaction by assuming control of the commodities purchased
and the responsibility to deliver the commodities sold. Revenue is recognized
when control transfers to the purchaser/customer at the delivery point based on
the price received. The transportation costs associated with these transactions
are presented as a component of costs of purchased oil. See "-Costs and expenses
- Costs of purchased oil."
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Costs and expenses
The following tables present information regarding costs and expenses and
selected average costs and expenses per BOE sold for the periods presented and
corresponding changes:
Three months ended June 30, 2020 compared to 2019
(in thousands except for per BOE sold data) 2020 2019 Change ($) Change (%)
Costs and expenses:
Lease operating expenses $ 20,591 $ 23,632 $ (3,041) (13) %
Production and ad valorem taxes 6,938 11,328 (4,390) (39) %
Transportation and marketing expenses 11,181 4,891 6,290 129 %
Midstream service expenses 815 607 208 34 %
Costs of purchased oil 16,117 30,172 (14,055) (47) %
General and administrative (excluding LTIP) 8,712 12,157 (3,445) (28) %
General and administrative (LTIP):
LTIP cash 463 (192) 655 341 %
LTIP non-cash 1,484 (909) 2,393 263 %
Organizational restructuring expenses 4,200 10,406 (6,206) (60) %
Depletion, depreciation and amortization 66,574 65,703 871 1 % Impairment expense 406,448 - 406,448 100 % Other operating expenses 1,117 1,020 97 10 % Total costs and expenses$ 544,640 $ 158,815 $ 385,825
243 % Selected average costs and expenses per BOE sold(1): Lease operating expenses
$ 2.40 $ 3.16 $ (0.76) (24) % Production and ad valorem taxes 0.81 1.51 (0.70) (46) % Transportation and marketing expenses 1.31 0.65 0.66 102 % Midstream service expenses 0.10 0.08 0.02 25 % General and administrative (excluding LTIP) 1.02 1.62 (0.60) (37) % Total selected operating expenses$ 5.64 $ 7.02 $ (1.38) (20) % General and administrative (LTIP): LTIP cash$ 0.05 $ (0.03) $ 0.08 267 % LTIP non-cash$ 0.17 $ (0.12) $ 0.29 242 % Depletion, depreciation and amortization$ 7.77 $ 8.78 $ (1.01)
(12) %
_____________________________________________________________________________
(1)Selected average costs and expenses per BOE sold are based on actual amounts and are not calculated using the rounded numbers presented in the table above.
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Six months ended June 30, 2020 compared to 2019
(in thousands except for per BOE sold data) 2020 2019 Change ($) Change (%)
Costs and expenses:
Lease operating expenses $ 42,631 $ 46,241 $ (3,610) (8) %
Production and ad valorem taxes 16,182 18,547 (2,365) (13) %
Transportation and marketing expenses 24,725 9,650 15,075 156 %
Midstream service expenses 1,985 2,210 (225) (10) %
Costs of purchased oil 95,414 62,863 32,551 52 %
General and administrative (excluding LTIP) 19,177 26,549 (7,372) (28) %
General and administrative (LTIP):
LTIP cash 596 - 596 100 %
LTIP non-cash 3,448 6,026 (2,578) (43) %
Organizational restructuring expenses 4,200 10,406 (6,206) (60) %
Depletion, depreciation and amortization 127,876 128,801 (925) (1) % Impairment expense 593,147 - 593,147 100 % Other operating expenses 2,223 2,072 151 7 % Total costs and expenses$ 931,604 $ 313,365 $ 618,239
197 % Selected average costs and expenses per BOE sold(1): Lease operating expenses
$ 2.59 $ 3.24 $ (0.65) (20) % Production and ad valorem taxes 0.98 1.30 (0.32) (25) % Transportation and marketing expenses 1.50 0.68 0.82 121 % Midstream service expenses 0.12 0.15 (0.03) (20) % General and administrative (excluding LTIP) 1.17 1.86 (0.69) (37) % Total selected operating expenses$ 6.36 $ 7.23 $ (0.87) (12) % General and administrative (LTIP): LTIP cash$ 0.04 $ -$ 0.04 100 % LTIP non-cash$ 0.21 $ 0.42 $ (0.21) (50) % Depletion, depreciation and amortization$ 7.78 $ 9.03 $ (1.25)
(14) %
_____________________________________________________________________________
(1)Selected average costs and expenses per BOE sold are based on actual amounts
and are not calculated using the rounded numbers presented in the table above.
Lease operating expenses ("LOE"). LOE, which includes workover expenses, and LOE
per BOE sold both decreased for the three and six months ended June 30, 2020 ,
compared to the same periods in 2019. We continue to focus on economic
efficiencies associated with the usage and procurement of products and services
related to LOE.
Production and ad valorem taxes. Production and ad valorem taxes decreased for
the three and six months ended June 30, 2020 , compared to the same periods in
2019. Production taxes, which are established by federal, state or local taxing
authorities, are based on and fluctuate in proportion to our oil, NGL and
natural gas sales revenues. Ad valorem taxes are based on and fluctuate in
proportion to the taxable value assessed by the various counties where our oil
and natural gas properties are located.
Transportation and marketing expenses. Transportation and marketing expenses
increased for the three and six months ended June 30, 2020 , compared to the same
periods in 2019. We recognize transportation and marketing expenses incurred for
the delivery of produced oil to customers in the U.S. Gulf Coast market via the
Bridgetex pipeline and the Gray Oak pipeline. We began shipment on the Gray Oak
pipeline during the fourth quarter of 2019. We plan to ship the majority of our
produced oil to the U.S. Gulf Coast . Additionally, we recognized marketing
expense due to negative natural gas prices in March 2020 .
Midstream service expenses. Midstream service expenses increased for the three
months ended June 30, 2020 and decreased for the six months ended June 30, 2020 ,
compared to the same periods in 2019. Midstream service expenses are costs
incurred to operate and maintain our (i) integrated oil and natural gas
gathering and transportation systems and related
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facilities, (ii) centralized oil storage tanks, (iii) natural gas lift, fuel for
drilling and completions activities and centralized compression infrastructure
and (iv) water storage, recycling and transportation facilities.
Costs of purchased oil. Costs of purchased oil decreased for the three months
ended June 30, 2020 , compared to the same period in 2019 due to a decrease in
oil prices, partially offset by increased shipments on pipelines. Costs of
purchased oil increased for the six months ended June 30, 2020 , compared to the
same period in 2019 due to increased shipments on pipelines, partially offset by
a decrease in oil prices. We are a firm shipper on both the Bridgetex and Gray
Oak pipelines, the latter of which we began shipment on during fourth-quarter
2019, and we utilize purchased oil to fulfill portions of our commitments. While
our long-haul transportation capacity on the Bridgetex pipeline and Gray Oak
pipeline is expected to exceed our net production, consistent with our historic
practice, we expect to continue to purchase third-party oil at the trading hubs
to satisfy the deficit in our associated long-haul transportation commitments.
General and administrative ("G&A"). G&A, excluding employee compensation expense
from our long-term incentive plan ("LTIP"), decreased for the three and six
months ended June 30, 2020 , compared to the same periods in 2019 mainly due to
decreases in employee-related costs as a result of the cumulative measures taken
during second-quarter 2020 and 2019 to align our cost structure with operational
activity, which included workforce reductions.
Cash LTIP expense increased for the three and six months ended June 30, 2020 ,
compared to the same periods in 2019, as these types of cash awards were not in
place in second-quarter 2019. Non-cash expense increased for the three months
ended June 30, 2020 and decreased for the six months ended June 30, 2020 ,
compared to the same periods in 2019. Our organizational restructurings resulted
in equity-based compensation expense, net reversals due to forfeitures during
each of the three months ended June 30, 2020 and 2019. In 2020, we took measures
to decrease LTIP award compensation percentages across our remaining employee
base. See Note 8 to our unaudited consolidated financial statements included
elsewhere in this Quarterly Report for information regarding our equity-based
compensation.
Organizational restructuring expenses. Organizational restructuring expenses are
related to our workforce reductions and retirements in an effort to reduce costs
and better position ourselves for the future in response to market conditions.
We incurred $4.2 million and $10.4 million of one-time charges during the three
and six months ended June 30, 2020 and 2019, respectively, comprised of
compensation, taxes, professional fees, outplacement and insurance-related
expenses. As of June 30, 2020 , no additional organizational restructuring
expenses are expected to be incurred. See Note 18 to our unaudited consolidated
financial statements included elsewhere in this Quarterly Report for further
discussion of the organizational restructurings.
Depletion, depreciation and amortization ("DD&A"). The following tables present
the components of our DD&A for the periods presented and corresponding changes:
Three months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Depletion of evaluated oil and natural gas
properties $ 63,305 $ 61,938 $ 1,367 2 %
Depreciation of midstream service assets 2,366 2,543 (177) (7) %
Depreciation and amortization of other fixed
assets 903 1,222 (319) (26) %
Total DD&A $ 66,574 $ 65,703 $ 871 1 %
Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Depletion of evaluated oil and natural gas
properties $ 121,057 $ 121,308 $ (251) - %
Depreciation of midstream service assets 4,958 5,044 (86) (2) %
Depreciation and amortization of other fixed
assets 1,861 2,449 (588) (24) %
Total DD&A $ 127,876 $ 128,801 $ (925) (1) %
DD&A remained consistent for the three and six months ended June 30, 2020
compared to the same periods in 2019. Depletion expense per BOE decreased by
$0.88 , or 11%, and by $1.15 , or 14%, for the three and six months ended June 30,
2020 , respectively, compared to the same periods in 2019. We expect depletion
expense to decrease as a result of full cost
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impairments incurred during 2020. For further discussion of our depletion base
and depletion expense per BOE, see Note 4 to our unaudited consolidated
financial statements included elsewhere in this Quarterly Report and "-Pricing
and reserves."
Impairment expense. The following table presents the components of our
impairment expense for the periods presented:
Six months ended June
Three months ended June 30, 30,
(in thousands) 2020 2019 2020 2019
Full cost ceiling impairment expense $ 406,448 $ - $ 583,630 $ -
Midstream service asset impairment expense - - 8,183 -
Line-fill and other inventories impairment expense - - 1,334 -
Total impairment expense $ 406,448 $ - $ 593,147 $ -
Our net book value of evaluated oil and natural gas properties exceeded the full
cost ceiling as of March 31, 2020 and June 30, 2020 , and, as a result, we
recorded full cost ceiling impairments of $177.2 million and $406.4 million
during the three months ended March 31, 2020 and June 30, 2020 , respectively.
There was no full cost ceiling impairment recorded for the six months ended June
30, 2019 . The full cost ceiling is based principally on the estimated future net
revenues from proved oil, NGL and natural gas reserves, which exclude the effect
of our commodity derivative transactions, discounted at 10%. The Realized Prices
are utilized to calculate the estimated future net revenues in the full cost
ceiling calculation. In the event the unamortized cost of evaluated oil and
natural gas properties being depleted exceeds the full cost ceiling, as defined
by the SEC , the excess is expensed in the period such excess occurs. Once
incurred, a write-down of oil and natural gas properties is not reversible. With
the continuing volatility in commodity prices, we may incur additional
significant write-downs on our evaluated oil and natural gas properties. See
Note 4 to our unaudited consolidated financial statements included elsewhere in
this Quarterly Report and "-Pricing and reserves" for additional information
regarding our full cost ceiling calculation.
Impairment losses are recorded on long-lived assets when indicators of
impairment are present and the undiscounted cash flows estimated to be generated
by those assets are less than the assets' carrying amount. Impairment is
measured based on the excess of the carrying amount over the fair value of the
asset. All inventory is carried at the lower of cost or net realizable value
("NRV"), with cost determined using the weighted-average cost method. For
additional discussion of our long-lived assets and inventories, see Note 10.b to
our unaudited consolidated financial statements included elsewhere in this
Quarterly Report.
Non-operating income (expense)
The following tables presents the components of non-operating income (expense),
net for the periods presented and corresponding changes:
Three months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Gain (loss) on derivatives, net $ (90,537) $ 88,394 $ (178,931) (202) %
Interest expense (27,072) (15,765) (11,307) (72) %
Litigation settlement - 42,500 (42,500) (100) %
Gain (loss) on disposal of assets, net 152 (670) 822 123 %
Other income (expense), net (16) 2,846 (2,862) (101) %
Write-off of debt issuance costs (1,103) - (1,103) (100) %
Total non-operating income (expense), net $ (118,576) $ 117,305 $ (235,881) (201) %
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Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Gain on derivatives, net $ 207,299 $ 40,029 $ 167,270 418 %
Interest expense (52,042) (31,312) (20,730) (66) %
Litigation settlement - 42,500 (42,500) (100) %
Loss on extinguishment of debt (13,320) - (13,320) (100) %
Loss on disposal of assets, net (450) (1,609) 1,159 72 %
Other income, net 75 3,713 (3,638) (98) %
Write-off of debt issuance costs (1,103) - (1,103) (100) %
Total non-operating income, net $ 140,459 $ 53,321 $ 87,138 163 %
Gain (loss) on derivatives, net. The following tables present the changes in the components of gain (loss) on derivatives, net for the periods presented and corresponding changes:
Three months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Non-cash gain (loss) on derivatives, net $ (126,816) $ 72,556 $ (199,372) (275) %
Settlements received for matured derivatives, net 86,872 23,480 63,392 270 %
Settlements paid for early terminations of
commodity derivatives, net - (5,409) 5,409 100 %
Premiums paid for commodity derivatives (50,593) (2,233) (48,360) (2,166) %
Gain (loss) on derivatives, net $ (90,537) $ 88,394 $ (178,931) (202) %
Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Non-cash gain on derivatives, net $ 123,774 $ 28,105 $ 95,669 340 %
Settlements received for matured derivatives, net 134,595 23,582 111,013 471 %
Settlements paid for early terminations of
commodity derivatives, net - (5,409) 5,409 100 %
Premiums paid for commodity derivatives (51,070) (6,249) (44,821) (717) %
Gain on derivatives, net $ 207,299 $ 40,029 $ 167,270 418 %
Non-cash gain (loss) on derivatives, net is the result of new, matured and
early-terminated contracts, including contingent consideration derivatives for
the period subsequent to the acquisition date and through the end of the
contingency period, and the changing relationship between our outstanding
contract prices and the future market prices in the forward curves, which we use
to calculate the fair value of our derivatives. In general, if outstanding
contracts are held constant, we experience gains during periods of decreasing
market prices and losses during periods of increasing market prices. Settlements
received or paid for matured derivatives are based on the settlement prices of
our matured derivatives compared to the prices specified in the derivative
contracts. During the three and six months ended June 30, 2020 , we recognized
significant non-cash losses and gains, respectively, in the net fair value of
our derivatives outstanding due to increases and decreases, respectively, in the
applicable futures curves that we have hedged. We entered into 2021 puts during
the three months ended June 30, 2020 and paid $50.6 million in premiums to
increase the put price received.
See Notes 9, 10.a and 19.b to our unaudited consolidated financial statements
included elsewhere in this Quarterly Report and "Item 3. Quantitative and
Qualitative Disclosures About Market Risk" for additional information regarding
our derivatives.
Interest expense. Interest expense increased for the three and six months ended
June 30, 2020 , compared to the same periods in 2019. These increases are mainly
due to the issuance of our January 2025 Notes and January 2028 Notes and the
extinguishment of our January 2022 Notes and March 2023 Notes, resulting in an
increase in the carrying amount of long-term debt along with higher fixed
interest rates. See Notes 6 and 19.a to our unaudited consolidated financial
statements included elsewhere in this Quarterly Report for additional
information regarding our long-term debt.
Loss on extinguishment of debt. We recognized a loss on extinguishment of debt
related to the difference between the consideration for tender offers, early
tender premiums and redemption prices and the net carrying amounts of the
extinguished January 2022 Notes and March 2023 Notes during the six months ended
June 30, 2020 . See Note 6.b to our
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unaudited consolidated financial statements included elsewhere in this Quarterly
Report for additional information regarding the extinguishment of our January
2022 Notes and March 2023 Notes.
Gain (loss) on disposal of assets, net. Gain (loss) on disposal of assets, net,
increased for the three and six months ended June 30, 2020 , compared to the same
periods in 2019. From time to time, we dispose of inventory, midstream service
assets and other fixed assets. The associated gain or loss recorded during the
period fluctuates depending upon the volume of the assets disposed, their
associated net book value and, in the case of a disposal by sale, the sale
price.
Write-off of debt issuance costs. We wrote-off $1.1 million of debt issuance
costs during the three and six months ended June 30, 2020 as a result of
decreases in the borrowing base and aggregate elected commitment of the Senior
Secured Credit Facility. There were no debt issuance costs written off during
the comparable periods. See Note 6.d to our unaudited consolidated financial
statements included elsewhere in this Quarterly Report for further discussion of
our debt issuance costs.
Income tax benefit (expense)
The following tables present income tax benefit (expense) for the periods
presented and corresponding changes:
Three months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Deferred $ 7,173 $ (1,751) $ 8,924 510 %
Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%) Deferred$ 4,756 $ (1,655) $ 6,411 387 % We are subject to federal and state income taxes and theTexas franchise tax. The deferred income tax benefit (expense) for the periods presented is attributed to deferredTexas franchise tax. As ofJune 30, 2020 , we determined it was more likely than not that our federal andOklahoma net deferred tax assets were not realizable through future net income. As ofJune 30, 2020 , a total valuation allowance of$404.5 million has been recorded to offset our federal andOklahoma net deferred tax assets, resulting in aTexas net deferred tax asset of$2.3 million . The effective tax rate for our operations was 1% for the three and six months endedJune 30, 2020 . For further discussion of our income taxes, see Note 16 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. Liquidity and capital resources In light of the recent world developments in 2020, we are closely monitoring our capital resources and business plans. Historically, our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings, proceeds from senior unsecured note offerings, borrowings under our Senior Secured Credit Facility and proceeds from asset dispositions. While we cannot predict the duration and negative impact of COVID-19 and OPEC+ actions on the energy industry, we believe our cash flows from operations, favorable hedges and availability under our Senior Secured Credit Facility provide sufficient liquidity to manage our cash needs and contractual obligations and to fund our expected capital expenditures. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties and infrastructure development. A significant portion of our capital expenditures can be adjusted and managed by us. We continually monitor the capital markets and our capital structure and consider which financing alternatives, including equity and debt capital resources, joint ventures and asset sales, are available to meet our future planned capital expenditures. We may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. Such financing alternatives, including capital markets transactions and, from time to time, debt and equity repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. For further discussion of our financing activities related to debt instruments, see Note 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. We continuously look for other opportunities to maximize shareholder value. 48 -------------------------------------------------------------------------------- Table of Contents Due to the inherent volatility in oil, NGL and natural gas prices and differences in the prices of oil, NGL and natural gas between where we produce and where we sell such commodities, we engage in commodity derivative transactions, such as puts, swaps, collars and basis swaps to hedge price risk associated with a portion of our anticipated sales volumes. Due to the inherent volatility in interest rates, we have entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of our anticipated outstanding debt under the Senior Secured Credit Facility. We will pay a fixed rate over the contract term for that portion. By removing a portion of the (i) price volatility associated with future sales volumes and (ii) interest rate volatility associated with anticipated outstanding debt, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. See "Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" below. See Notes 9.a, 9.b and 19.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our (i) commodity hedge restructuring during the six months endedJune 30, 2020 and corresponding summary of open commodity derivative positions as ofJune 30, 2020 for commodity derivatives that were entered into throughJune 30, 2020 , (ii) interest rate derivative and (iii) summary of open Brent ICE swap positions as ofJune 30, 2020 updated for derivatives that were entered into throughAugust 5, 2020 , respectively. We continually seek to maintain a financial profile that provides operational flexibility. As ofJune 30, 2020 , we had cash and cash equivalents of$15.7 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of$405.9 million , resulting in total liquidity of$421.6 million . As ofAugust 4, 2020 , we had cash and cash equivalents of$21.0 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of$380.9 million , resulting in total liquidity of$401.9 million . We believe that our operating cash flows and the aforementioned liquidity sources provide us with the financial resources to manage our business needs, to implement our currently planned capital expenditure budget and, at our discretion, to fund any share repurchases, pay down, repurchase or refinance debt or adjust our planned capital expenditure budget. Cash flows The following table presents our cash flows for the periods presented and corresponding changes: Six months ended June 30, 2020 compared to 2019 (in thousands) 2020 2019 Change ($) Change (%) Net cash provided by operating activities$ 171,562 $ 261,269 $ (89,707) (34) % Net cash used in investing activities (268,604) (292,974) 24,370 8 % Net cash provided by financing activities 71,932 42,354 29,578 70 %
Net increase (decrease) in cash and cash equivalents
$ 10,649 $ (35,759) (336) % Cash flows from operating activities Net cash provided by operating activities decreased during the six months endedJune 30, 2020 , compared to the same period in 2019. Notable cash changes include (i) an increase of$71.6 million in net settlements received for matured and early terminated derivatives, net of premiums paid, mainly due to decreases in commodity prices, (ii) a decrease in oil, NGL and natural gas sales revenues of$127.2 million , (iii) a decrease in non-recurring litigation proceeds of$42.5 million and (iv) an increase of$43.8 million due to net changes in operating assets and liabilities. Other contributing factors are increases for costs of purchased oil and transportation and marketing expenses. The decrease in oil, NGL and natural gas sales revenues is due to a 44% decrease in average sales price per BOE and was partially offset by a 15% increase in total volumes sold. For additional information, see "-Results of operations", "-Costs and expenses" and "-Non-operating income (expense)". Our operating cash flows are sensitive to a number of variables, the most significant of which are the volatility of oil, NGL and natural gas prices, mitigated to the extent of our commodity derivatives' exposure, and sales volume levels. Regional and worldwide economic activity, weather, infrastructure, transportation capacity to reach markets, costs of operations, legislation and regulations, including potential government production curtailments, and other variable factors significantly impact the prices of these commodities. Recently, however, commodity prices have been most impacted by the effects of COVID-19 on demand and the effects of the OPEC+ actions and related transportation and storage constraints, particularly in theState of Texas , on supply. These factors are not within our control and are difficult to predict. For additional information on risks related to our business, see "Part II. Item 1A. Risk Factors" included elsewhere in this Quarterly Report and "Part I. Item 1A. Risk Factors" in our 2019 Annual Report. 49 -------------------------------------------------------------------------------- Table of Contents Cash flows from investing activities Net cash used in investing activities decreased for the six months endedJune 30, 2020 , compared to the same period in 2019, mainly due to a decrease in capital expenditures for oil and natural gas properties, partially offset by an increase in acquisitions of oil and natural gas properties. See Note 3 to our unaudited consolidated financial statements included elsewhere in the Quarterly Report for additional discussion of our acquisitions of oil and natural gas properties. The following table presents the components of our cash flows from investing activities for the periods presented and corresponding changes: Six months ended June 30, 2020 compared to 2019 (in thousands) 2020 2019 Change ($) Change (%)
Acquisitions of oil and natural gas properties, net
$ (2,880) $ (20,683) (718) % Capital expenditures: Oil and natural gas properties (241,939) (284,616) 42,677 15 % Midstream service assets (1,761) (5,449) 3,688 68 % Other fixed assets (2,069) (965) (1,104) (114) %
Proceeds from dispositions of capital assets, net of selling costs
728 936 (208) (22) %
Net cash used in investing activities $ (268,604) $ (292,974) $ 24,370 8 %
Cash flows from financing activities
Net cash provided by financing activities increased for the six months ended
June 30, 2020 , compared to the same period in 2019. Notable cash changes include
the issuance of our January 2025 Notes and January 2028 Notes, partially offset
by the extinguishment of our January 2022 Notes and March 2023 Notes and
payments and borrowings on our Senior Secured Credit Facility. For further
discussion of our financing activities related to debt instruments, see Note 6
to our unaudited consolidated financial statements included elsewhere in this
Quarterly Report.
The following table presents the components of our cash flows from financing
activities for the periods presented and corresponding changes:
Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Borrowings on Senior Secured Credit Facility $ - $ 80,000 $ (80,000) (100) %
Payments on Senior Secured Credit Facility (100,000) (35,000) (65,000) (186) %
Issuance of January 2025 Notes and January 2028
Notes 1,000,000 - 1,000,000 100 %
Extinguishment of debt (808,855) - (808,855) (100) %
Stock exchanged for tax withholding (762) (2,646) 1,884 71 %
Payments for debt issuance costs (18,451) - (18,451) (100) %
Net cash provided by financing activities $ 71,932 $ 42,354 $ 29,578 70 %
Expected capital expenditures
We intend to operate within cash flow in 2020 (excluding non-budgeted
acquisitions) and, therefore, our capital spending in 2020 will ultimately be
influenced by commodity price changes, production levels and, among other
factors, changes in service costs and drilling and completions efficiencies. In
early 2020, the Company significantly reduced planned operational activities as
commodity prices suffered from historic declines amid COVID-19 related demand
destruction and OPEC+ pricing and supply decisions, dramatically reducing
expected returns on capital investments. A subsequent increase in commodity
prices, paired with service cost reductions, has driven expected returns on our
Howard County acreage back to levels that support a resumption of activity and,
beginning in September 2020 , the Company plans to operate a completions crew in
Howard County . We currently expect capital expenditures for 2020 to be
approximately $340 million to $350 million . We are prepared to adjust our
capital expenditures further if oil, NGL and natural gas prices continue to
exhibit volatility. We do not have a specific acquisition budget since the
timing and size of acquisitions cannot be accurately forecasted.
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The following tables present the components of our costs incurred, excluding
non-budgeted acquisition costs, for the periods presented and corresponding
changes:
Three months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Oil and natural gas properties $ 75,941 $ 128,780 $ (52,839) (41) %
Midstream service assets 671 3,064 (2,393) (78) %
Other fixed assets 1,774 453 1,321 292 %
Total costs incurred, excluding non-budgeted
acquisition costs $ 78,386 $ 132,297 $ (53,911) (41) %
Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Oil and natural gas properties $ 228,809 $ 289,002 $ (60,193) (21) %
Midstream service assets 1,594 6,437 (4,843) (75) %
Other fixed assets 2,597 967 1,630 169 %
Total costs incurred, excluding non-budgeted
acquisition costs $ 233,000 $ 296,406 $ (63,406) (21) %
See Note 4 to our unaudited consolidated financial statements included elsewhere
in this Quarterly Report for additional information regarding our costs incurred
in the exploration and development of oil and natural gas properties.
The amount, timing and allocation of capital expenditures are largely
discretionary and within management's control. If oil, NGL and natural gas
prices are below our acceptable levels, or costs are above our acceptable
levels, we may choose to defer a portion of our budgeted capital expenditures
until later periods to achieve the desired balance between sources and uses of
liquidity and prioritize capital projects that we believe have the highest
expected returns and potential to generate near-term cash flow. Subject to
financing alternatives, we may also increase our capital expenditures
significantly to take advantage of opportunities we consider to be attractive.
We continually monitor and may adjust our projected capital expenditures in
response to world developments, such as those we are experiencing in 2020, as
well as success or lack of success in drilling activities, changes in prices,
availability of financing and joint venture opportunities, drilling and
acquisition costs, industry conditions, the timing of regulatory approvals, the
availability of rigs and supplies, changes in service costs, contractual
obligations, internally generated cash flow and other factors both within and
outside our control.
We are the borrower under our Senior Secured Credit Facility and a party to the
indentures governing our Senior Unsecured Notes.
Senior Secured Credit Facility
As of June 30, 2020 , the Senior Secured Credit Facility, which matures on
April 19, 2023 , had a maximum credit amount of $2.0 billion , a borrowing base
and an aggregate elected commitment of $725.0 million each, with $275.0 million
outstanding and was subject to an interest rate of 2.19%. Additionally, the
Senior Secured Credit Facility provides for the issuance of letters of credit,
limited to the lesser of total capacity or $80.0 million . As of June 30, 2020
and December 31, 2019 , we had one letter of credit outstanding of $44.1 million
and $14.7 million , respectively, under the Senior Secured Credit Facility. The
Senior Secured Credit Facility is fully and unconditionally guaranteed by LMS
and GCM. On July 14, 2020 , we borrowed $45.0 million on the Senior Secured
Credit Facility. On July 31, 2020 , we made a $20 million payment on the Senior
Secured Credit Facility. As a result, the outstanding balance under the Senior
Secured Credit Facility was $300.0 million as of August 4, 2020 .
On August 5, 2020 , we received a waiver from the lenders under our Senior
Secured Credit Facility of certain representations and warranties relating to
our March 31, 2020 quarterly results. Such representations and warranties were
incorrect at the time they were given due to our previously disclosed accounting
error. Additionally, due to the accounting error we were temporarily not in
compliance with our financial reporting covenants. As of the filing of our
Restated First Quarter Financials, we regained compliance with the financial
reporting covenants under our Senior Secured Credit Facility and the waiver
cured
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the past defaults of our representations and warranties. The Senior Secured
Credit Facility contains both financial and non-financial covenants, all of
which we were in compliance with for all periods presented.
January 2025 Notes and January 2028 Notes
The following table presents principal amounts and applicable interest rates for
our outstanding January 2025 Notes and January 2028 Notes (together the "Senior
Unsecured Notes") as of June 30, 2020 :
(in millions, except for interest rates) Principal Interest rate
January 2025 Notes $ 600.0 9.500 %
January 2028 Notes 400.0 10.125 %
Total Senior Unsecured Notes $ 1,000.0
The net proceeds from the January 2025 Notes and January 2028 Notes were used to
fund the tender offers and redemptions of the remaining principle amounts of the
January 2022 Notes and March 2023 Notes. See Notes 6.a and 6.b to our unaudited
consolidated financial statements included elsewhere in this Quarterly Report
for further discussion of our Senior Unsecured Notes.
Supplemental Guarantor information
As discussed in Note 6.a to our unaudited consolidated financial statements
included elsewhere in this Quarterly Report, on January 24, 2020 , we issued
$600.0 million in aggregate principal amount of the January 2025 Notes and
$400.0 million in aggregate principal amount of the January 2028 Notes. As of
June 30, 2020 , $1.0 billion of our Senior Unsecured Notes remained outstanding.
Each of our wholly owned subsidiaries, LMS and GCM (each, a "Guarantor," and
together, the "Guarantors"), jointly and severally, and fully and
unconditionally, guarantees the January 2025 Notes and the January 2028 Notes.
We do not have any non-guarantor subsidiaries.
The guarantees are senior unsecured obligations of each Guarantor and rank
equally in right of payment with other existing and future senior indebtedness
of such Guarantor, and senior in right of payment to all existing and future
subordinated indebtedness of such Guarantor. The guarantees of the Senior
Unsecured Notes by the Guarantors are subject to certain Releases. The
obligations of each Guarantor under its note guarantee are limited as necessary
to prevent such note guarantee from constituting a fraudulent conveyance under
applicable law. Further, the rights of holders of the Senior Unsecured Notes
against the Guarantors may be limited under the U.S. Bankruptcy Code or state
fraudulent transfer or conveyance law. Laredo is not restricted from making
investments in the Guarantors and the Guarantors are not restricted from making
intercompany distributions to Laredo or each other.
As we do not have any non-guarantor subsidiaries, the assets, liabilities and
results of operations of the combined issuer and Guarantors are not materially
different than the corresponding amounts presented in our unaudited consolidated
financial statements included elsewhere in this Quarterly Report. Accordingly,
we have omitted the summarized financial information of the issuer and the
Guarantors that would otherwise be required.
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Obligations and commitments
The following table presents significant contractual obligations and commitments
as of June 30, 2020 and December 31, 2019 and their associated changes:
($ in thousands, except % change) June 30, 2020 December 31, 2019 Change ($) Change (%)
Senior Unsecured Notes(1)$ 1,606,563 $ 939,844$ 666,719 71 % Firm sale and transportation commitments(2) 306,381 322,790 (16,409) (5) % Senior Secured Credit Facility(3) 275,000 375,000 (100,000) (27) % Asset retirement obligations(4) 65,245 62,718 2,527 4 % Lease commitments(5) 29,899 35,606 (5,707) (16) % Commodity derivative deferred premiums(6) - 477 (477) (100) % Total$ 2,283,088 $ 1,736,435 $ 546,653 31 %
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(1)Values presented include both our principal and interest obligations. The increase in such balance as ofJune 30, 2020 is due to (i) the issuance of ourJanuary 2025 Notes andJanuary 2028 Notes, (ii) the extinguishment of ourJanuary 2022 Notes andMarch 2023 Notes and (iii) an increase in our interest rates as a result of such financing transactions. See Notes 6.a and 6.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our Senior Unsecured Notes. (2)We have committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, we are subject to firm transportation payments on excess pipeline capacity and other contractual penalties. The decrease in such commitments as ofJune 30, 2020 is mainly due to our fulfillment of contractual commitments, partially offset by changes to existing sales commitments. See Note 12.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our firm sale and transportation commitments. (3)This table does not include future loan advances, repayments, commitment fees or other fees on our Senior Secured Credit Facility as we cannot determine with accuracy the timing of such items. Additionally, this table does not include interest expense as it is a floating rate instrument and we cannot determine with accuracy the future interest rates to be charged. The decrease in such balance as ofJune 30, 2020 is due to our payments. As ofJune 30, 2020 , the principal on our Senior Secured Credit Facility is due onApril 19, 2023 . See Note 19.a for our borrowing and payment on our Senior Secured Credit Facility subsequent toJune 30, 2020 . (4)Amounts represent our asset retirement obligation liabilities. See Note 14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our asset retirement obligations. (5)Amounts represent our minimum lease payments. The decrease in lease commitments as ofJune 30, 2020 is mainly due to settlements paid for our fulfillment of lease commitments, partially offset by a modification to an existing lease commitment. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our leases. (6)Amounts represent payments required for deferred premiums on our commodity derivative contracts. The decrease in premiums as ofJune 30, 2020 is due to premiums paid for commodity derivatives. All deferred premiums have settled as ofJune 30, 2020 . See Note 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our deferred premiums. Non-GAAP financial measures The non-GAAP financial measures of Free Cash Flow and Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP financial measures should be considered in conjunction with net income or loss and other performance measures prepared in accordance with GAAP, such as operating income or loss or cash flows from operating activities. Free Cash Flow and Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of liquidity or financial performance. 53
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Table of Contents Free Cash Flow Free Cash Flow, a non-GAAP financial measure, does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Free Cash Flow is useful to management and investors in evaluating operating trends in our business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies. The following table presents a reconciliation of net cash provided by operating activities (GAAP) to cash flows from operating activities before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs, for the calculation of Free Cash Flow (non-GAAP) for the periods presented:
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