VITAL ENERGY, INC. The following discussion and analysis of our financial condition and results of operations is for the three months endedMarch 31, 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: Three months ended March 31, 2020 compared to 2019 (in thousands) 2020 2019 Change (#) Change (%) Oil sales volumes (MBbl) 2,655 2,534 121 5 % Oil equivalents sales volumes (MBOE) 7,874 6,775 1,099 16 %
Oil, NGL and natural gas sales(1)
$ 235,095 $ (9,491 ) $ 244,586 2,577 % Free Cash Flow (a non-GAAP financial measure)(2)$ (57,523 ) $ (50,965 ) $ (6,558 ) (13 )% Adjusted EBITDA (a non-GAAP financial measure)(2)$ 116,848 $
122,906
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(1) Our oil, NGL and natural gas sales decreased as a result of a 33% decrease
in average sales price per BOE and were partially offset by a 16% increase
in MBOE volumes sold.
(2) See page 44 for discussions regarding and calculations of these non-GAAP
financial measures.
Recent developments
COVID-19
In December 2019 , a highly transmissible and pathogenic strain of coronavirus
surfaced in China , which has and is continuing to spread throughout the world,
including the U.S. On January 30, 2020 , the World Health Organization declared
the outbreak of COVID-19 a "Public Health Emergency of International Concern,"
and on March 11, 2020 , the World Health Organization characterized the outbreak
as a "pandemic". Federal, state and local authorities have recommended
stay-at-home orders and social distancing guidelines for U.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 and U.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.
Volatility in Commodity Prices
In early March 2020 , concurrent with the spread of COVID-19 to the U.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 agree and some producers instead announced planned production increases,
after which oil prices declined sharply. By mid-March
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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 go 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 . We maintain an active, multi-year commodity derivatives strategy to minimize commodity price volatility and support cash flows needed for operations. For April throughDecember 2020 , we currently have oil derivatives in place for 5.4 million barrels swapped at a weighted-average price of$59.50 WTI per barrel and 1.8 million barrels swapped at a weighted-average price of$63.07 Brent per barrel. We entered into derivatives subsequent toMarch 31, 2020 , and among these, we entered into oil derivatives for 2021 with$50.6 million premiums settled at the respective contracts' inception. For 2021, we currently have oil derivatives in place for 5.6 million barrels at a weighted-average floor price of$53.13 Brent per barrel. In light of current market conditions, we have taken significant steps to proactively manage our cash flow and preserve liquidity. To prioritize Free Cash Flow, balance sheet strength and returns in a volatile commodity price environment, we reduced expected capital expenditures for 2020 to$290 million from$450 million . We further reduced expected capital expenditures for 2020 to$265 million , driven by additional refinements, including savings for drilling and completions services and postponements of capital projects, with$220 million allocated to drilling and completions activities and$45 million allocated to infrastructure, land and other capitalized costs. Although we have reduced activity dramatically, we are prepared to reduce it further for an extended period if necessary. We will utilize this slowdown to improve on our best in class operations and to continue to reduce expenses to the lowest and most efficient cost structure possible. Potential Reverse Stock Split and Authorized Share Reduction OnMarch 17, 2020 , our board of directors authorized an amendment to our Certificate of Incorporation to effect, at their discretion, (i) a Reverse Stock Split that will reduce the number of shares of outstanding Common Stock in accordance with a ratio to be determined by our board of directors within a range of 1-for-5 and 1-for-20 currently outstanding and (ii) an Authorized Share Reduction resulting in a decrease from 450,000,000 authorized shares of Common Stock to between 22,500,000 and 90,000,000 authorized shares of Common Stock. The amendments must be approved by stockholders for the board of directors to effect the Reverse Stock Split and the Authorized Share Reduction. We expect the annual meeting of stockholders to be held onMay 14, 2020 . Delisting Notice OnMarch 26, 2020 , we received a notice from the NYSE that the average closing price of our shares of Common Stock, over the prior 30-consecutive trading day period was below$1.00 per share, which is the minimum average closing price per share required to maintain continued listing on the NYSE. We have untilDecember 5, 2020 to regain compliance with the minimum share price requirement. If we do not regain compliance, the NYSE will commence suspension and delisting procedures. We intend to consider all available options to regain compliance with the minimum share price requirement, including, if necessary, by implementing the Reverse Stock Split and Authorized Share Reduction. See Note 7.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the Reverse Stock Split and Authorized Share Reduction. See "Part II. Item 1A. Risk Factors" included elsewhere in this Quarterly Report. 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 since the Determination Date of the Borrowing Base then in effect 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 after 30
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April 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 Consolidated Total Leverage Ratio of not greater than 4.25 to 1.00 remains unchanged. Pricing and reserves Our results of operations are heavily influenced by oil, NGL and natural gas prices, which have experienced significant declines into second-quarter 2020. Oil, NGL and natural gas price fluctuations are currently impacted by the COVID-19 pandemic and policies of OPEC+, which have increased changes in global and regional supply and demand and economic conditions, and caused market uncertainty, transportation and storage constraints and a variety of additional issues. 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 18.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 toMarch 31, 2020 . Our reserves as ofMarch 31, 2020 andDecember 31, 2019 are reported in three streams: oil, NGL and natural gas. The Realized Prices utilized to value our proved reserves as ofMarch 31, 2020 andMarch 31, 2019 , were$52.47 per Bbl for oil,$10.47 per Bbl for NGL and$0.28 per Mcf for natural gas, and$56.72 per Bbl for oil,$20.46 per Bbl for NGL and$1.09 per Mcf for natural gas, respectively. 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 and, as such, we recorded a first-quarter non-cash full cost ceiling impairment of$16.7 million . No such impairments were recorded during the three months endedMarch 31, 2019 . As more specifically addressed in "Low commodity price impact on our first-quarter 2020 and potentially on our second-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 second quarter of 2020 and Remaining Year 2020 (defined below), which will have an adverse effect on our results of operations. See Note 4 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. 31
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The following table presents our depletion expense for our evaluated oil and natural gas properties per BOE sold for the periods presented:
Three months ended March 31 , 2020 compared to 2019
2020 2019 Change ($) Change (%)
Depletion expense per BOE sold $ 7.33 $ 8.76 Low commodity price impact on our first-quarter 2020 and potentially on our second-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 second-quarter 2020 and Remaining Year 2020, which will have an adverse effect on our results 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 on 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. Set forth below are calculations of potential future impairments of our evaluated oil and natural gas properties for the second-quarter 2020 and for the period ofApril 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 second-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 second-quarter 2020 full cost ceiling calculation has been prepared by substituting (i)$43.96 per Bbl for oil, (ii)$7.56 per Bbl for NGL and (iii)$0.38 per Mcf for natural gas (collectively, the "Pro Forma Second-Quarter Prices") for the respective Realized Prices as ofMarch 31, 2020 . All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of low commodity prices on the second-quarter 2020 Realized Prices that will be utilized in our full cost ceiling calculation. The Pro Forma Second-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 endedApril 1, 2020 and holding theApril 1, 2020 prices constant for the remaining eleventh and twelfth months of the calculation. Based solely on the substitution of the Pro Forma Second-Quarter Prices into ourMarch 31, 2020 proved reserve estimates, the implied second-quarter 2020 impairment would be$448 million . Our hypothetical Remaining Year 2020 full cost ceiling calculation has been prepared by substituting (i)$34.80 per Bbl for oil, (ii)$5.22 per Bbl for NGL and (iii)$0.88 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 32
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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 four months endedApril 1, 2020 and using strip pricing as ofApril 20, 2020 for the Remaining Year 2020. Based solely on the substitution of the Pro Forma Remaining Year Prices into ourMarch 31, 2020 proved reserve estimates, the implied Remaining Year 2020 impairment would be$753 million . We believe that substituting these prices into ourMarch 31, 2020 proved reserve estimates may help provide users with an understanding of the potential impact on our second-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 impairment for the three months endedMarch 31, 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 ofMarch 31, 2020 , we had assembled 134,614 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. The following table presents our sources of revenue as a percentage of total revenues: Three months ended March 31, 2020 compared to 2019 2020 2019 Change (#) Change (%) Oil sales 59 % 62 % (3 )% (5 )% NGL sales 6 % 15 % (9 )% (60 )% Natural gas sales 2 % 6 % (4 )% (67 )% Midstream service revenues 1 % 1 % - % - % Sales of purchased oil 32 % 16 % 16 % 100 % Total 100 % 100 % 33
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Oil, NGL and natural gas sales volumes, revenues and prices The following table presents information regarding our oil, NGL and natural gas sales volumes, sales revenues and average sales prices:
Three months ended March 31 , 2020 compared to 2019
2020 2019 Change (#) Change (%)
Sales volumes:
Oil (MBbl) 2,655 2,534 121 5 %
NGL (MBbl) 2,467 2,099 368 18 %
Natural gas (MMcf) 16,512 12,849 3,663 29 %
Oil equivalents (MBOE)(1)(2) 7,874 6,775 1,099 16 %
Average daily oil equivalent sales
volumes (BOE/D)(2) 86,532 75,276 11,256 15 %
Average daily oil sales volumes
(Bbl/D)(2) 29,178 28,157 1,021 4 %
Sales revenues (in thousands):
Oil $ 119,978 $ 129,171 $ (9,193 ) (7 )%
NGL 11,558 32,235 (20,677 ) (64 )%
Natural gas 4,349 11,970 (7,621 ) (64 )%
Total oil, NGL and natural gas sales
revenues $ 135,885 $ 173,376 $ (37,491 ) (22 )%
Average sales prices(2):
Oil ($/Bbl)(3) $ 45.19 $ 50.97 $ (5.78 ) (11 )%
NGL ($/Bbl)(3) $ 4.68 $ 15.36 $ (10.68 ) (70 )%
Natural gas ($/Mcf)(3) $ 0.26 $ 0.93 $ (0.67 ) (72 )%
Average sales price ($/BOE)(3) $ 17.26 $ 25.59 $ (8.33 ) (33 )%
Oil, with commodity
derivatives ($/Bbl)(4) $ 56.59 $ 47.66 $ 8.93 19 %
NGL, with commodity
derivatives ($/Bbl)(4) $ 6.85 $ 15.33 $ (8.48 ) (55 )%
Natural gas, with commodity
derivatives ($/Mcf)(4) $ 0.94 $ 1.11 $ (0.17 ) (15 )%
Average sales price, with commodity
derivatives ($/BOE)(4) $ 23.21 $ 24.68 $ (1.47 ) (6 )%
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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 endedMarch 31, 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, 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.
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The following table presents 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, presented
above:
Three months ended March 31, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Settlements received (paid) for matured
commodity derivatives:
Oil $ 31,147 $ (2,095 ) $ 33,242 1,587 %
NGL 5,337 (57 ) 5,394 9,463 %
Natural gas 11,239 2,254 8,985 399 %
Total $ 47,723 $ 102 $ 47,621 46,687 %
Premiums paid previously or upon
settlement attributable to commodity
derivatives that matured during the
respective period:
Oil $ (877 ) $ (6,300 ) $ 5,423 86 %
Changes in average sales prices and sales volumes caused the following changes
to our oil, NGL and natural gas revenues between the three months ended
March 31, 2020 and 2019:
(in thousands) Oil NGL Natural gas Total
2019 Revenues $ 129,171 $ 32,235 $ 11,970 $ 173,376
Effect of changes in average sales
prices (15,364 ) (26,326 ) (11,034 ) (52,724 )
Effect of changes in sales volumes 6,171 5,649 3,413 15,233
2020 Revenues $ 119,978 $ 11,558 $ 4,349 $ 135,885
Change ($) $ (9,193 ) $ (20,677 ) $ (7,621 ) $ (37,491 )
Change (%) (7 )% (64 )% (64 )% (22 )%
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, and decreases are continuing.
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 March 31, 2020 , compared to the
same period in 2019 is due to an 11% decrease in average oil sales prices and
was partially offset by a 5% 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 March 31, 2020 , compared to the
same period in 2019 is due to a 70% decrease in average NGL sales prices and was
partially offset by an 18% 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 decrease in natural gas sales revenue for the
three months ended March 31, 2020 , compared to the same period in 2019 is due to
a 72% decrease in average natural gas sales prices and was partially offset by a
29% increase in natural gas sales volumes.
The following table presents midstream service and sales of purchased oil
revenues:
Three months ended March 31, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Midstream service revenues $ 2,683 $ 2,883 $ (200 ) (7 )%
Sales of purchased oil $ 66,424 $ 32,688 $ 33,736 103 %
Midstream service revenues. Our midstream service revenues decreased for the
three months ended March 31, 2020 compared to the same period 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. These 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
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latter of which we began shipment on during fourth-quarter 2019, and we utilize
purchased oil to fulfill portions of our commitments.
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."
Costs and expenses
The following table presents information regarding costs and expenses and
selected average costs and expenses per BOE sold:
Three months ended March 31, 2020 compared to 2019
(in thousands except for per BOE sold
data) 2020 2019 Change ($) Change (%)
Costs and expenses:
Lease operating expenses $ 22,040 $ 22,609 $ (569 ) (3 )%
Production and ad valorem taxes 9,244 7,219 2,025 28 %
Transportation and marketing expenses 13,544 4,759 8,785 185 %
Midstream service expenses 1,170 1,603 (433 ) (27 )%
Costs of purchased oil 79,297 32,691 46,606 143 %
General and administrative (excluding
LTIP) 10,465 14,392 (3,927 ) (27 )%
General and administrative (LTIP):
LTIP cash 133 192 (59 ) (31 )%
LTIP non-cash 1,964 6,935 (4,971 ) (72 )%
Depletion, depreciation and amortization 61,302 63,098 (1,796 ) (3 )%
Impairment expense 26,250 - 26,250 100 %
Other operating expenses 1,106 1,052 54 5 %
Total costs and expenses $ 226,515 $ 154,550 $ 71,965 47 %
Selected average costs and expenses per
BOE sold(1):
Lease operating expenses $ 2.80 $ 3.34 $ (0.54 ) (16 )%
Production and ad valorem taxes 1.17 1.07 0.10 9 %
Transportation and marketing expenses 1.72 0.70 1.02 146 %
Midstream service expenses 0.15 0.24 (0.09 ) (38 )%
General and administrative (excluding
LTIP) 1.33 2.12 (0.79 ) (37 )%
Total selected operating expenses $ 7.17 $ 7.47 $ (0.30 ) (4 )%
General and administrative (LTIP):
LTIP cash $ 0.02 $ 0.03 $ (0.01 ) (33 )%
LTIP non-cash $ 0.25 $ 1.02 $ (0.77 ) (75 )%
Depletion, depreciation and amortization $ 7.78 $ 9.31 _____________________________________________________________________________
(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 months ended March 31, 2020 , compared
to the same period 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 increased for
the three months ended March 31, 2020 , compared to the same period in 2019. We
received a $4.5 million production tax refund, related to additional marketing
costs claimed for fiscal years 2013 through 2016, recorded during the first
quarter of 2019.
Transportation and marketing expenses. Transportation and marketing expenses
increased for the three months ended March 31, 2020 , compared to the same period
in 2019. We recognize transportation and marketing expenses incurred for the
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delivery of produced oil to two customers in theU.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 theU.S. Gulf Coast . Additionally, we recognized$2.0 million in marketing expense due to negative natural gas prices inMarch 2020 . Midstream service expenses. Midstream service expenses decreased for the three months endedMarch 31, 2020 , compared to the same period 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 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 increased for the three months endedMarch 31, 2020 , compared to the same period in 2019. We are a firm shipper on both the Bridgetex andGray 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 andGray 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 transportation commitments. General and administrative ("G&A"). G&A, excluding employee compensation expense from our long-term incentive plan ("LTIP"), decreased for the three months endedMarch 31, 2020 , compared to the same period in 2019 mainly due to a decrease in employee-related costs as a result of the measures taken during second-quarter 2019 to align our cost structure with operational activity, which included a workforce reduction. The decrease in cash and non-cash LTIP expense is due to (i) LTIP award forfeitures related to the second-quarter 2019 workforce reduction, which were still being expensed in first-quarter 2019 and (ii) a decrease in 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. Depletion, depreciation and amortization ("DD&A"). The following table presents the components of our DD&A for the periods presented: Three months ended March 31, 2020 compared to 2019 (in thousands) 2020 2019 Change ($) Change (%) Depletion of evaluated oil and natural gas properties$ 57,752 $ 59,370 $ (1,618 ) (3 )% Depreciation of midstream service assets 2,592 2,501 91 4 % Depreciation and amortization of other fixed assets 958 1,227 (269 ) (22 )% Total DD&A$ 61,302 $ 63,098 $ (1,796 ) (3 )% DD&A decreased for the three months endedMarch 31, 2020 , compared to the same period in 2019, mainly due to depletion. Depletion decreased due to the previous increase in ourDecember 31, 2019 proved reserve volume partially offset by an increase in production and an increase in the depletion base, which was mainly due to acquisitions and development and partially offset by full cost impairments. Depletion expense per BOE decreased by$1.43 , or 16%, for the three months endedMarch 31, 2020 , compared to the same period in 2019. 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. Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling as ofMarch 31, 2020 , and, as a result, we recorded a full cost ceiling impairment of$16.7 million for the three months endedMarch 31, 2020 . There was no full cost ceiling impairment recorded for the three months endedMarch 31, 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 discounted 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 theSEC , 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. 37
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Additionally, for the three months endedMarch 31, 2020 , we recorded impairment expense of (i)$1.3 million for inventory, pertaining to line-fill and other inventories and (ii)$8.2 million for long-lived assets, pertaining to midstream service assets. There were no comparable impairments of inventory or long-lived assets recorded during the three months endedMarch 31, 2019 . Impairment losses are recorded on long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. All inventory is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method. For additional discussion of our long-lived assets, see Note 10.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. Non-operating income (expense) The following table presents the components of non-operating income (expense), net: Three months ended March 31, 2020 compared to 2019 (in thousands) 2020 2019 Change ($) Change (%) Gain (loss) on derivatives, net$ 297,836 $ (48,365 ) $ 346,201 716 % Interest expense (24,970 ) (15,547 ) (9,423 ) (61 )% Loss on extinguishment of debt (13,320 ) - (13,320 ) (100 )% Loss on disposal of assets, net (602 ) (939 ) 337 36 % Other income, net 91 867 (776 ) (90 )%
Total non-operating income (expense), net
505 %
Gain (loss) on derivatives, net. The following table presents the changes in the components of gain (loss) on derivatives, net:
Three months ended March 31, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Non-cash gain (loss) on derivatives, net
664 %
Settlements received for matured
commodity derivatives, net 47,723 102 47,621 46,687 %
Premiums paid for commodity derivatives (477 ) (4,016 ) 3,539 88 %
Gain (loss) on derivatives, net $ 297,836 $ (48,365 ) $ 346,201 716 %
Non-cash gain (loss) on derivatives, net is the result of new, matured and
early-terminated contracts 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 months ended March 31, 2020 , we recognized
significant non-cash gains in the net fair value of our derivatives outstanding
due to decreases in the applicable futures curves that we have hedged.
See Notes 9 and 10.a 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 months ended
March 31, 2020 , compared to the same period in 2019. This increase is 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 interest
rates, partially offset by a decrease in the amount outstanding on our Senior
Secured Credit Facility. See Notes 6 and 18.b to our unaudited consolidated
financial statements included elsewhere in this Quarterly Report for additional
information regarding our debt and our interest rate derivative entered into
subsequent to March 31, 2020 , respectively.
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 three months
ended March 31, 2020 . See Note 6.b to our 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.
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Loss on disposal of assets, net. Loss on disposal of assets, net, decreased for the three months endedMarch 31, 2020 , compared to the same period 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. Income tax (expense) benefit The following table presents income tax (expense) benefit for the periods presented: Three months ended March 31, 2020 compared to 2019 (in thousands) 2020 2019 Change ($) Change (%) Deferred $ (2,417 )$ 96 $ (2,513 ) (2,618 )% The deferred income tax (expense) benefit for the periods presented is attributed to deferredTexas franchise tax. We are subject to federal and state income taxes and theTexas franchise tax. As ofMarch 31, 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 ofMarch 31, 2020 , a total valuation allowance of$255.9 million has been recorded to offset our federal andOklahoma net deferred tax assets, resulting in aTexas net deferred tax liability of$4.9 million . The effective tax rate for our operations was 1.0% for the three months endedMarch 31, 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 market 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. 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. By removing a portion of the price volatility associated with future sales volumes, 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 Note 9 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our hedge restructuring during the three months endedMarch 31, 2020 and corresponding summary of open commodity derivative positions as ofMarch 31, 2020 for commodity derivatives that were entered into throughMarch 31, 2020 . Additionally, see Note 18.b for a summary of derivatives that were entered into subsequent toMarch 31, 2020 . We continually seek to maintain a financial profile that provides operational flexibility. As ofMarch 31, 2020 , we had cash and cash equivalents of$62.8 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of$660.3 million , resulting in total liquidity of$723.1 million . As ofMay 6, 2020 , we had cash and cash equivalents of$5.0 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit and a reduction in our borrowing base, of$405.9 million , resulting in total liquidity of$410.9 million . We believe that our operating cash flows and the aforementioned liquidity sources provide us with the financial resources to manage our business needs, to implement our currently planned capital expenditure budget and, at our discretion, to fund any share repurchases, pay down, repurchase or refinance debt or adjust our planned capital expenditure budget. Cash flows The following table presents our cash flows: Three months ended March 31, 2020 compared to 2019 (in thousands) 2020 2019 Change ($) Change (%) Net cash provided by operating activities$ 109,589 $ 77,458 $ 32,131 41 %
Net cash used in investing activities (159,791 ) (155,453 ) (4,338 )
(3 )%
Net cash provided by financing
activities 72,122 77,388 (5,266 ) (7 )%
Net increase (decrease) in cash and
cash equivalents $ 21,920 $ (607
)
Cash flows from operating activities Net cash provided by operating activities increased during the three months endedMarch 31, 2020 , compared to the same period in 2019. Notable cash changes include (i) an increase of$48.2 million in net changes in operating assets and liabilities, (ii) an increase of$51.2 million in settlements received for matured commodity derivatives, net of premiums paid and (iii) a decrease in oil, NGL and natural gas sales revenues of$37.5 million . The decrease in oil, NGL and natural gas sales revenues is due to a 33% decrease in average sales prices per BOE and was partially offset by a 16% increase in total volumes sold. See "-Results of operations" for additional discussion of changes in our oil, NGL and natural gas sales revenues. Other contributing factors are increases for costs of purchased oil and transportation and marketing expenses. See "-Costs and expenses" and "-Non-operating income (expense)" for additional information. 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. Cash flows from investing activities Net cash used in investing activities increased for the three months endedMarch 31, 2020 , compared to the same period in 2019, mainly due to acquisitions of oil and natural gas properties, partially offset by a decrease in capital expenditures for 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. 39
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The following table presents the components of our cash flows from investing
activities:
Three months ended March 31, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Acquisitions of oil and natural gas
properties, net $ (22,876 ) $ - $ (22,876 ) (100 )%
Capital expenditures:
Oil and natural gas properties (135,376 ) (152,729 ) 17,353 11 %
Midstream service assets (761 ) (2,262 ) 1,501 66 %
Other fixed assets (829 ) (505 ) (324 ) (64 )%
Proceeds from dispositions of capital
assets, net of selling costs 51 43 8 19 %
Net cash used in investing activities
Cash flows from financing activities Net cash provided by financing activities decreased for the three months endedMarch 31, 2020 , compared to the same period in 2019. Notable cash changes include the issuance of ourJanuary 2025 Notes andJanuary 2028 Notes, partially offset by the extinguishment of ourJanuary 2022 Notes andMarch 2023 Notes, payments on our Senior Secured Credit Facility and payments for debt issuance costs. 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: Three months ended March 31, 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 ) - (100,000 ) (100 )% Issuance ofJanuary 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 (640 ) (2,612 ) 1,972 75 % Payments for debt issuance costs (18,383 ) - (18,383 ) (100 )% Net cash provided by financing activities$ 72,122 $ 77,388
Expected capital expenditures Our goal is to achieve positive Free Cash Flow in 2020 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. Due to the significant decrease in oil, NGL and natural gas prices, we adjusted our expected capital expenditures, excluding non-budgeted acquisitions, to$265.0 million for calendar year 2020. We are prepared to decrease our capital expenditures further if oil, NGL and natural gas prices remain weak. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. The following table presents the components of our costs incurred, excluding non-budgeted acquisition costs: Three months ended March 31, 2020 compared to 2019 (in thousands) 2020 2019
Change ($) Change (%)
Oil and natural gas properties(1)
(5 )%
Midstream service assets 923 3,373 (2,450 ) (73 )%
Other fixed assets 823 514 309 60 %
Total costs incurred, excluding
non-budgeted acquisition costs $ 154,614 $ 164,109 $ (9,495 ) (6 )%
_____________________________________________________________________________
(1) 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.
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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 consistently 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. Debt 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 ofMarch 31, 2020 , the Senior Secured Credit Facility, which matures onApril 19, 2023 , had a maximum credit amount of$2.0 billion , a borrowing base and an aggregate elected commitment of$950.0 million each, with$275.0 million outstanding and was subject to an interest rate of 2.43%. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which we were in compliance with for all periods presented. 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 ofMarch 31, 2020 andDecember 31, 2019 , we had one letter of credit outstanding of$14.7 million under the Senior Secured Credit Facility. The Senior Secured Credit Facility is fully and unconditionally guaranteed by LMS and GCM. 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 under our Senior Secured Credit Facility were reduced to$725.0 million each, among other changes. Additionally, subsequent toMarch 31, 2020 , our outstanding letter of credit was increased to$44.1 million .January 2025 Notes andJanuary 2028 Notes The following table presents principal amounts and applicable interest rates for our outstanding Senior Unsecured Notes as ofMarch 31, 2020 : (in millions, except for interest rates) Principal Interest rate January 2025 Notes$ 600.0 9.500 % January 2028 Notes 400.0 10.125 % Total Senior Unsecured Notes$ 1,000.0 The net proceeds from theJanuary 2025 Notes andJanuary 2028 Notes were used to fund the tender offers and redemptions of the remaining principle amounts of theJanuary 2022 Notes andMarch 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, onJanuary 24, 2020 , we issued$600.0 million in aggregate principal amount of theJanuary 2025 Notes and$400.0 million in aggregate principal amount of theJanuary 2028 Notes (together the "Senior Unsecured Notes"). As ofMarch 31, 2020 ,$1.0 billion of our Senior Unsecured Notes remained outstanding. Each of our wholly owned subsidiaries, LMS and GCM (each, a "Guarantor," and together, the "Guarantors"), jointly and severally, and fully and unconditionally, guarantees, theJanuary 2025 Notes and theJanuary 2028 Notes. We do not have any non-guarantor subsidiaries. The guarantees are senior unsecured obligations of each Guarantor and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor, and senior in right of payment to all existing and future subordinated 41
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indebtedness of such Guarantor. The guarantees of the Senior Unsecured Notes by the Guarantors are subject to certain Releases. The obligations of each Guarantor under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. Further, the rights of holders of the Senior Unsecured Notes against the Guarantors may be limited under theU.S. Bankruptcy Code or state fraudulent transfer or conveyance law.Laredo is not restricted from making investments in the Guarantors and the Guarantors are not restricted from making intercompany distributions toLaredo or each other. As we do not have any non-guarantor subsidiaries, the assets, liabilities and results of operations of the combined issuer and Guarantors are not materially different than the corresponding amounts presented in our unaudited consolidated financial statements included elsewhere in this Quarterly Report. Accordingly, we have omitted the summarized financial information of the issuer and the Guarantors that would otherwise be required. Obligations and commitments The following table presents significant contractual obligations and commitments as ofMarch 31, 2020 andDecember 31, 2019 and their associated changes: ($ in thousands, except % change) March 31, 2020 December 31, 2019 Change ($) Change (%) Senior Unsecured Notes(1)$ 1,606,563 $ 939,844$ 666,719 71 % Firm sale and transportation commitments(2) 314,741 322,790 (8,049 ) (2 )% Senior Secured Credit Facility(3) 275,000 375,000 (100,000 ) (27 )% Asset retirement obligations(4) 64,213 62,718 1,495 2 % Lease commitments(5) 30,590 35,606 (5,016 ) (14 )% Commodity derivative deferred premiums(6) - 477 (477 ) (100 )% Total$ 2,291,107 $ 1,736,435$ 554,672 32 %
____________________________________________________________________________
(1) Values presented include both our principal and interest obligations. The
increase in such balance as of
of our
of our January 2022 Notes and March 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 statementsincluded 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 of March 31,
2020 is mainly due to our fulfillment of contractual commitments,
partially offset by changes to existing sales commitments. See Note 12.cto 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 of
repayments. As of
Credit Facility is due on
(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 of
our fulfillment of lease commitments. 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 of
to premiums paid for commodity derivatives. See Note 10.a to our unaudited
consolidated financial statements included elsewhere in this Quarterly
Report for additional discussion of our deferred premiums.
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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. 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):
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