LIBERTY ENERGY INC. The following discussion and analysis of our financial condition and results of operations should be read in conjunction with "Item 6. Selected Financial Data" and our audited consolidated and combined financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Reporting on Form 10-K under "Cautionary Note Regarding Forward-Looking Statements" and "Item 1A. Risk Factors." We assume no obligation to update any of these forward-looking statements. This section of this Annual Report on Form 10-K generally discusses 2019 and 2018 items and year-to-year comparisons between 2019 and 2018. For discussion of year endedDecember 31, 2017 , as well as the year ended 2018 compared to the year endedDecember 31, 2017 , refer to Part II, Item 7- "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our 2018 Annual Report on Form 10-K. Overview We are an independent provider of hydraulic fracturing services and goods to onshore oil and natural gas E&P companies inNorth America . We have grown from one active hydraulic fracturing fleet inDecember 2011 to 24 active fleets inFebruary 2020 . We added one fleet during the year endedDecember 31, 2019 and one one fleet inJanuary 2020 . We provide our services primarily in thePermian Basin , theEagle Ford Shale , theDJ Basin , theWilliston Basin , theSan Juan Basin and thePowder River Basin . We believe the following characteristics both distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our proprietary databases ofU.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; and (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe to be the best talent in our field, enabling us to be one of the safest and most efficient hydraulic fracturing companies inthe United States . Recent Trends and Outlook Demand for hydraulic fracturing services and goods is predominantly influenced by the level of drilling and completion activity by E&P companies, which, in turn, depends largely on the current and anticipated profitability of developing oil and natural gas reserves, the availability of capital to E&P companies, and takeaway capacity in each basin. More specifically, demand for hydraulic fracturing services is driven by the completion of hydraulic fracturing stages in unconventional wells, which, in turn, is driven by several factors including rig count, well count, service intensity and the timing and style of well completions. Additionally, pricing for hydraulic fracturing services is impacted by the demand factors described above, as well as by the supply of actively marketed and staffed hydraulic fracturing fleets. The price of WTI in 2019 decreased from 2018. The price of WTI averaged$56.98 ,$65.23 , and$50.80 during 2019, 2018, and 2017, respectively. According to a report byBaker Hughes , aGE company ("Baker Hughes"), the horizontal rig count inNorth America averaged 826, 900, and 737 during 2019, 2018 and 2017, respectively. During 2019 and 2018, E&P companies have increasingly come under investor pressure for better returns than those achieved over the last decade. As a result, debt and equity capital markets, which previously funded drilling and completions activity beyond E&P companies' operating cash flow, tightened, causing an increased level of capital discipline that has resulted in a lower level of drilling and completions expenditures. 2019 E&P capital expenditures were lower than those in 2018 and 2020 E&P capital expenditures are expected to be less than 2019. The pricing dynamic entering into 2020 is challenging. Total industry horizontal frac stages inNorth America were up marginally in 2019, 6% from 2018, compared to a 34% increase in 2018 from 2017, according toCoras Research, LLC ("Coras"). However, efficiency gains across the industry have raised the number of frac stages completed by each fleet, which implies a decrease in the active frac fleets needed to meet demand. The slowing pace of frac activity led to progressively lower demand for frac fleets through the second half of 2019, resulting in pricing pressure on our services. The substantial oversupply of frac equipment in the second half of 2019 was the pricing backdrop for 2020 dedicated fleet negotiations. 44 -------------------------------------------------------------------------------- Table of Contents Although we are seeing reductions in the supply of staffed frac fleets in the market and announcements of permanent retirement of older equipment, there continues to be an oversupply of frac fleets in the market which is holding down pricing. As such, while we cannot predict with any certainty when pricing of our frac services will increase, we would not expect pricing to improve until the supply of actively staffed frac equipment better balances with the demand. Until pricing improves, we expect that increased profitability will have to come from technology, increased efficiency and enhanced processes. Although there is uncertainty in the market about the level of customers' drilling and completion activity in 2020, we expect demand for Liberty's high-efficiency frac fleets to remain strong during 2020 due to the diversity of Liberty's operating footprint, conversations with our customers and other factors and, as a result, we chose to activate our 24th frac fleet earlier this year as part of growing our business with larger customers to support their long-term development programs. Based on our current visibility into our customers' plans for 2020, we believe this level of demand is likely to continue through the year. Increase in Drilling Efficiency and Service Intensity of Completions Over the past decade, E&P companies have focused on exploiting the vast resource potential available across many ofNorth America's unconventional resource plays through the application of horizontal drilling and completion technologies, including the use of multi-stage hydraulic fracturing, in order to increase recovery of oil and natural gas. As E&P companies have improved drilling and completion techniques to maximize return and efficiency, we believe several long term trends have emerged which have materially increased the service intensity of current completions. Improved drilling economics from horizontal drilling and greater rig efficiencies. Unconventional resources are increasingly being targeted through the use of horizontal drilling. According toBaker Hughes , as reported onJanuary 10, 2020 , horizontal rigs accounted for approximately 89% of all rigs drilling inthe United States , up from 74% as ofDecember 31, 2014 . Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully-assembled rigs to automatically "walk" from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. At the same time, E&P companies are shifting their development plans to incorporate multi-well pad development, which allows them to drill multiple horizontal wellbores from the same pad or location. The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Coras, has dropped from 28 days in 2014 to 20 days in 2019. Increased complexity and service intensity of horizontal well completions. In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of stages has also increased. From 2012 to 2019, the average stages per horizontal well have increased from 23 stages per well to 40 stages per well, according to Liberty FracTrends evaluation of wells in 12 liquid rich formations. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Coras, from six million pounds per well in 2014 to over 14 million pounds per well in 2019. These industry trends will directly benefit hydraulic fracturing companies like us that have the expertise and technological innovations to effectively service today's more efficient oilfield drilling activity and the increasing complexity and intensity of well completions. Given the expected returns that E&P companies have reported for new well development activities due to improved rig efficiencies and increasing well completion complexity and intensity, we expect these industry trends to continue. How We Generate Revenue We currently generate revenue through the provision of hydraulic fracturing services and goods. These services and goods are performed under a variety of contract structures, primarily MSAs as supplemented by statements of work, pricing agreements and specific quotes. A portion of our statements of work, under MSAs, include provisions that establish pricing arrangements for a period of up to one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer. 45 -------------------------------------------------------------------------------- Table of Contents Our hydraulic fracturing services are performed in sections, which we refer to as fracturing stages. The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer's well completion design. We recognize revenue for each fracturing stage completed, although our revenue per completed fracturing stage varies depending on the actual volumes and types of proppants, chemicals and fluid utilized for each fracturing stage. The number of fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages. Costs of Conducting Our Business The principal expenses involved in conducting our business are direct cost of personnel, services and materials used in the provision of services, general and administrative expenses, and depreciation and amortization. A large portion of the costs we incur in our business are variable based on the number of hydraulic fracturing jobs and the requirements of services provided to our customers. We manage the level of our fixed costs, except depreciation and amortization, based on several factors, including industry conditions and expected demand for our services. How We Evaluate Our Operations We use a variety of qualitative, operational and financial metrics to assess our performance. First and foremost of these is a qualitative assessment of customer satisfaction because ensuring we are a valuable partner to our customers is the key to achieving our quantitative business metrics. Among other measures, management considers each of the following: •Revenue; •Operating Income; •EBITDA; •Adjusted EBITDA; •Annualized Adjusted EBITDA per Average Active Fleet; •Net Income Before Taxes; and •Earnings per Share. Revenue We analyze our revenue by comparing actual monthly revenue to our internal projections for a given period and to prior periods to assess our performance. We also assess our revenue in relation to the number of fleets we have deployed (revenue per average active fleet) from period to period. Operating Income We analyze our operating income, which we define as revenues less direct operating expenses, depreciation and amortization and general and administrative expenses, to measure our financial performance. We believe operating income is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income to our internal projections for a given period and to prior periods. EBITDA and Adjusted EBITDA We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as new fleet or new basin start-up costs, costs of asset acquisition, gain or loss on the disposal of assets, asset impairment charges, bad debt reserves, and non-recurring expenses that management does not consider in assessing ongoing operating performance. Annualized Adjusted EBITDA per Average Active Fleet is calculated as Adjusted EBITDA annualized, divided by the Average Active Fleets for the same period. See "-Comparison of Non-GAAP Financial Measures" for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income, the most directly comparable financial measure calculated and presented in accordance with GAAP. 46 -------------------------------------------------------------------------------- Table of Contents Results of Operations Year EndedDecember 31, 2019 , Compared to Year EndedDecember 31, 2018 Years Ended December 31, Description 2019 2018 Change (in thousands) Revenue$ 1,990,346 $ 2,155,136 $ (164,790) Cost of services, excluding depreciation and amortization shown separately 1,621,180 1,628,753 (7,573) General and administrative 97,589 99,052 (1,463) Depreciation and amortization 165,379 125,110 40,269 Loss (gain) on disposal of assets 2,601 (4,342) 6,943 Operating income 103,597 306,563 (202,966) Interest expense, net 14,681 17,145 (2,464) Net income before taxes 88,916 289,418 (200,502) Income tax expense 14,052 40,385 (26,333) Net income 74,864 249,033 (174,169)
Less: Net income attributable to Predecessor, prior to the Corporate Reorganization
- 8,705 (8,705)
Less: Net income attributable to non-controlling
interests 35,861 113,979 (78,118)
Net income attributable to Liberty Oilfield Services
Inc. stockholders $ 39,003 $ 126,349 $ (87,346)
Revenue
Our revenue decreased $164.8 million , or 7.6%, to $2.0 billion for the year
ended December 31, 2019 compared to $2.2 billion for the year ended December 31,
2018 . The overall decrease was due to a 13.7% decrease in revenue per average
active fleet offset by a 7.0% increase in average active fleets deployed. Our
revenue per average active fleet decreased to approximately $87.3 million for
the year ended December 31, 2019 as compared to approximately $101.2 million for
the year ended December 31, 2018 , based on 22.8 and 21.3 average active fleets
during those respective periods. The decrease in revenue per active fleet was
due to decreases in market prices for fracturing services compared to the prior
year.
Cost of Services
Cost of services (excluding depreciation and amortization) decreased $7.6
million , or 0.5%, to $1.6 billion for the year ended December 31, 2019 compared
to $1.6 billion for the year ended December 31, 2018 . The lower expense is
primarily due to a $78.2 million decrease in materials for the year ended
December 31, 2019 compared to the same period in 2018. While material volumes
increased significantly during 2019 as compared to 2018, unit prices have come
down with the increased use of lower cost local sand. The decrease in costs were
partially offset by higher repairs and maintenance costs which increased by
$31.1 million as well as increased personnel costs of approximately $30.6
million compared to the same period in 2018.
General and Administrative Expenses
General and administrative expenses decreased by $1.5 million , or 1.5%, to $97.6
million for the year ended December 31, 2019 compared to $99.1 million for the
year ended December 31, 2018 . This decrease is primarily attributed to a
decrease in start up costs of approximately $5.5 million , partially offset by an
increase of approximately $4.9 million in non cash stock based compensation
expense attributable to the Company's second year of restricted stock unit
grants under its Long Term Incentive Plan.
Depreciation and Amortization
Depreciation and amortization expense increased $40.3 million , or 32.2%, to
$165.4 million for the year ended December 31, 2019 compared to $125.1 million
for the year ended December 31, 2018 , primarily due to three additional
hydraulic fracturing fleets deployed during 2018 that were in service for all of
2019, as well as one additional fleet deployed during the year ended December
31, 2019 .
Loss (Gain) on Disposal of Assets
Loss (gain) on disposal of assets in 2019 decreased $6.9 million to a loss of
$2.6 million for the year ended December 31, 2019 compared to a gain of $4.3
million for the year ended December 31, 2018 . The decrease is primarily due to a
gain recognized during the year ended December 31, 2018 on insurance proceeds
received in excess of losses incurred for damaged equipment resulting from an
accidental fire in November 2018 .
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Operating Income
We realized operating income of $103.6 million for the year ended December 31,
2019 compared to operating income of $306.6 million for the year ended December
31, 2018 , primarily due to a decrease in revenue related to a decrease in demand
for our services in conjunction with a decrease in market prices as well as an
increase in depreciation and amortization costs related to additional fleets
deployed during 2019 and 2018.
Interest Expense, net
The decrease in interest expense, net of $2.5 million , or 14.4%, to $14.7
million during the year ended December 31, 2019 compared to $17.1 million during
the year ended December 31, 2018 , was primarily due to an increase of
approximately $2.4 million from higher interest income primarily driven by an
agreement entered into with Liberty Resources in 2019 for a note receivable as
well as interest income earned on short term cash investments. For further
details of this related party transaction, see Note 12-Related Party
Transactions to the consolidated and combined financial statements included in
"Item 8. Financial Statements and Supplementary Data."
Net Income Before Taxes
We realized net income before taxes of $88.9 million for the year ended December
31, 2019 compared to net income of $289.4 million for the year ended December
31, 2018 . The decrease in net income before taxes is primarily attributable to a
decrease in market prices for our services related to oversupply of North
American hydraulic fracturing fleets for the year ended December 31, 2019 .
Income Tax Expense
As a pass-through entity prior to the IPO, the Predecessor was subject only to
the Texas margin tax at a statutory rate of 1.0% and was not subject to U.S.
federal income tax. Subsequent to the IPO, the pre-tax net income attributable
to the Company is taxed at a combined U.S. federal and state tax rate of
approximately 23.0%, while no tax is provided for the income attributable to the
non-controlling interests, which remains pass-through income attributable to the
holders of non-controlling interests. We recognized $14.1 million of tax expense
in the year ended December 31, 2019 , an effective rate of 15.8%, compared to
$40.4 million recognized during the year ended December 31, 2018 , an effective
rate of 14.0%. This decrease in income tax expense is mainly attributable to the
net decrease in operating income, the components of which are discussed above.
Comparison of Non-GAAP Financial Measures
We view EBITDA and Adjusted EBITDA as important indicators of performance. We
define EBITDA as net income before interest, income taxes, depreciation and
amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the
effects of items such as new fleet or new basin start-up costs, costs of asset
acquisitions, gain or loss on the disposal of assets, asset impairment charges,
bad debt reserves and non-recurring expenses that management does not consider
in assessing ongoing performance.
Our Board, management, investors and lenders use EBITDA and Adjusted EBITDA to
assess our financial performance because it allows them to compare our operating
performance on a consistent basis across periods by removing the effects of our
capital structure (such as varying levels of interest expense), asset base (such
as depreciation and amortization) and other items that impact the comparability
of financial results from period to period. We present EBITDA and Adjusted
EBITDA because we believe they provide useful information regarding the factors
and trends affecting our business in addition to measures calculated under GAAP.
Note Regarding Non-GAAP Financial Measures
EBITDA and Adjusted EBITDA are not financial measures presented in accordance
with GAAP. We believe that the presentation of these non-GAAP financial measures
will provide useful information to investors in assessing our financial
performance and results of operations. Net income (loss) is the GAAP measure
most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial
measures should not be considered as alternatives to the most directly
comparable GAAP financial measure. Each of these non-GAAP financial measures has
important limitations as an analytical tool due to exclusion of some but not all
items that affect the most directly comparable GAAP financial measures. You
should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for
an analysis of our results as reported under GAAP. Because EBITDA and Adjusted
EBITDA may be defined differently by other companies in our industry, our
definitions of these non-GAAP financial measures may not be comparable to
similarly titled measures of other companies, thereby diminishing their utility.
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The following tables present a reconciliation of EBITDA and Adjusted EBITDA to
our net income, which is the most directly comparable GAAP measure for the
periods presented:
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 : EBITDA
and Adjusted EBITDA
Years Ended December 31,
Description 2019 2018 Change
(in thousands)
Net income $ 74,864 $ 249,033 $ (174,169)
Depreciation and amortization 165,379 125,110 40,269
Interest expense, net 14,681 17,145 (2,464)
Income tax expense 14,052 40,385 (26,333)
EBITDA $ 268,976 $ 431,673 $ (162,697)
Fleet start-up costs 4,519 10,069 (5,550)
Asset acquisition costs - 632 (632)
(Gain) loss on disposal of assets 2,601 (4,342) 6,943
Bad debt reserve 1,053 - 1,053
Advisory services fees - 202 (202)
Adjusted EBITDA $ 277,149 $ 438,234 $ (161,085)
EBITDA was $269.0 million for the year ended December 31, 2019 compared to
$431.7 million for the year ended December 31, 2018 . Adjusted EBITDA was $277.1
million for the year ended December 31, 2019 compared to $438.2 million for the
year ended December 31, 2018 . The decreases in EBITDA and Adjusted EBITDA
resulted from the decreased revenue and other factors described above under the
captions Revenue, Cost of Services, General and Administrative Expenses and
Depreciation and Amortization for Year Ended December 31, 2019 , Compared to Year
Ended December 31, 2018 .
Liquidity and Capital Resources
Overview
Historically, our primary sources of liquidity to date have been cash flows from
operations, proceeds from our IPO, and borrowings under our Credit Facilities.
We expect to fund operations and organic growth with cash flows from operations
and available borrowings under our Credit Facilities. We may incur additional
indebtedness or issue equity in order to fund growth opportunities that we
pursue via acquisition. Our primary uses of capital have been capital
expenditures to support organic growth and funding ongoing operations, including
maintenance and fleet upgrades.
Cash and cash equivalents increased by $9.4 million to $112.7 million as of
December 31, 2019 compared to $103.3 million as of December 31, 2018 . We believe
that our operating cash flow and available borrowings under our Credit
Facilities will be sufficient to fund our operations for at least the next
twelve months.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
Years Ended December 31,
Description 2019 2018 Change
(in thousands)
Net cash provided by operating activities
$ (90,158) Net cash used in investing activities (194,347) (255,492)
61,145
Net cash used in financing activities (57,375) (8,775)
(48,600)
Net increase in cash and cash equivalents
Analysis of Cash Flow Changes Between the Years EndedDecember 31, 2019 andDecember 31, 2018 Operating Activities. Net cash provided by operating activities was$261.1 million for the year endedDecember 31, 2019 , compared to net cash provided by operating activities of$351.3 million for the year endedDecember 31, 2018 . The$90.2 million decrease in cash from operating activities was primarily attributable to a$164.8 million decrease in revenues, offset by an increase of$24.9 million from changes in working capital between periods, and to a lesser extent by lower cash taxes, costs of goods sold, and general and administrative expenses. 49 -------------------------------------------------------------------------------- Table of Contents Investing Activities. Net cash used in investing activities was$194.3 million for the year endedDecember 31, 2019 , compared to$255.5 million for the year endedDecember 31, 2018 . The$61.1 million decrease in net cash used in investing activities was primarily due to fewer hydraulic frac fleets deployed during 2019 than were deployed during 2018. Financing Activities. Net cash used in financing activities was$57.4 million for the year endedDecember 31, 2019 , compared to net cash used in financing activities of$8.8 million for the year endedDecember 31, 2018 . The$48.6 million increase in cash used in financing activities was primarily due to cash provided by financing activities in 2018 from the IPO and Corporate Reorganization offset by increased repayments under the Credit Facilities and increased share repurchases in 2018 compared to 2019. During 2018,$200.2 million of net proceeds were raised from the IPO and Corporate Reorganization. Share repurchases were$82.9 million in 2018 compared to$18.4 million in 2019. Repayments of borrowings under the Credit Facilities were$92.8 million in 2018 compared to$1.8 million in 2019. Quarterly dividends and distributions were$11.6 million in 2018 compared to$22.5 million in 2019. Payments on finance lease obligations were zero in 2018 compared to$12.1 million in 2019. Other distributions and advances to non-controlling interest holders were$21.3 million in 2018 compared to de minimis amounts in 2019. Debt Agreements OnSeptember 19, 2017 , the Company entered into two new credit agreements for a revolving line of credit up to$250.0 million (the "ABL Facility") and a$175.0 million term loan (the "Term Loan Facility", and together with the ABL Facility the "Credit Facilities"). Following is a description of the ABL Facility and the Term Loan Facility. ABL Facility Under the terms of the ABL Facility, up to$250.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. As ofDecember 31, 2019 , the borrowing base was calculated to be$171.1 million , and the Company had no borrowings outstanding, except for a letter of credit in the amount of$0.3 million , with$170.8 million of remaining availability. Borrowings under the ABL Facility bear interest at LIBOR or a base rate, plus an applicable LIBOR margin of 1.5% to 2.0% or base rate margin of 0.5% to 1.0%, as defined in the ABL Facility credit agreement. The unused commitment is subject to an unused commitment fee of 0.375% to 0.5%. Interest and fees are payable in arrears at the end of each month, or, in the case of LIBOR loans, at the end of each interest period. The ABL Facility matures on the earlier of (i)September 19, 2022 and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility, which matures onSeptember 19, 2022 . Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by the Company,Liberty LLC andR/C IV Non-U.S. LOS Corp. , aDelaware corporation ("R/C IV") and a subsidiary of the Company, as parent guarantors. Term Loan Facility The Term Loan Facility provides for a$175.0 million term loan, of which$110.0 million remained outstanding as ofDecember 31, 2019 . Amounts outstanding bear interest at LIBOR or a base rate, plus an applicable margin of 7.625% or 6.625%, respectively, and the weighted average rate on borrowings was 9.4% as ofDecember 31, 2019 . The Company is required to make quarterly principal payments of 1% per annum of the initial principal balance, commencing onDecember 31, 2017 , with final payment due at maturity onSeptember 19, 2022 . The Term Loan Facility is collateralized by the fixed assets of LOS and its subsidiaries, and is further secured by the Company,Liberty LLC and R/C IV, as parent guarantors. The Credit Facilities include certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. The Term Loan Facility requires mandatory prepayments upon certain dispositions of property or issuance of other indebtedness, as defined, and annually a percentage of excess cash flow (25% to 50%, depending on leverage ratio, of consolidated net income less capital expenditures and other permitted payments, commencing with the year endingDecember 31, 2018 ). Certain mandatory prepayments and optional prepayments are subject to a prepayment premium of 3% of the prepaid principal declining annually to 1% during the first three years of the term of the Term Loan Facility. The Credit Facilities are not subject to financial covenants unless liquidity, as defined in the respective credit agreements, drops below a specified level. Under the ABL Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined in the credit agreement governing the ABL Facility, of 1.0 to 1.0 for each period if excess availability is less than 10% of the borrowing base or$12.5 million , whichever is greater. Under the Term Loan Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0 for each trailing twelve-month period if the Company's liquidity, as defined, is less than$25.0 million for at least five consecutive business days. The Company was in compliance with these covenants as ofDecember 31, 2019 . 50 -------------------------------------------------------------------------------- Table of Contents Contractual Obligations The table below provides estimates of the timing of future payments that we are contractually obligated to make based on agreements in place atDecember 31, 2019 . Payments Due by Period ($ in thousands) Less than 1 More than 5 Total year 1 - 3 years 4 - 5 years years ABL Facility(1) $ - $ - $ - $ - $ - Term Loan Facility(1) 109,966 1,750 108,216 - - Estimated interest payments(2) 28,024 10,473 17,551 - - Operating lease obligations(3) 63,235 18,262 20,945 8,011 16,017 Finance lease obligations(4) 51,168 26,407 24,761 - - Purchase commitments(5) 525,507 349,096 157,408 19,003 - Obligations under the TRAs(6) 50,302 1,821 20,470 8,111 19,900 Total$ 828,202 $ 407,809 $ 349,351 $ 35,125 $ 35,917 (1)Payments on our ABL Facility and Term Loan Facility exclude interest payments. Payments are based on debt balances as ofDecember 31, 2019 . (2)Estimated interest payments are based on debt balances as ofDecember 31, 2019 . Interest rates applied are based on the weighted average rate as ofDecember 31, 2019 . (3)Operating lease obligations include payments for leased facilities, equipment and vehicles. (4)Finance lease obligations include payments for leased vehicles. (5)Purchase commitments represent payments under supply agreements for the purchase and transportation of proppants. Some of the agreements include minimum monthly purchase commitments, including agreements under which a shortfall fee may be applied. The shortfall fee may be offset by purchases in excess of the minimum requirement during future periods, as allowed for by each agreement. (6)The timing and amount(s) of the aggregate payments due under the TRAs may vary based on a number of factors, including the timing and amount of the taxable income we generate each year and the tax rate then applicable. Tax Receivable Agreements In connection with the IPO, onJanuary 17, 2018 , the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, inU.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each of the TRA Holders, of (i) certain increases in tax basis that occur as a result of the Company's acquisition (or deemed acquisition forU.S. federal income tax purposes) of all or a portion of such TRA Holders' Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right of each Liberty Unit Holder (the "Redemption Right"), subject to certain limitations, to causeLiberty LLC to acquire all or a portion of its Liberty LLC Units for, atLiberty LLC's election, (A) shares of our Class A Common Stock at the specific redemption ratio or (B) an equivalent amount of cash, or, upon the exercise of the Redemption Right, the right ofLiberty Inc. (instead ofLiberty LLC ) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder (the "Call Right") for, at its election, (1) one share of Class A Common Stock or (2) an equivalent amount of cash, (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with Accounting Standard Codification ("ASC") Topic 450, Contingencies. If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company's obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs. 51 -------------------------------------------------------------------------------- Table of Contents Income Taxes Following the IPO, the Company is a corporation and is subject toU.S. federal, state and local income tax on its share ofLiberty LLC's taxable income. As a result of the IPO and Corporate Reorganization, the Company recorded deferred tax assets and liabilities for the difference between the book value of assets and liabilities for financial reporting purposes and those amounts applicable for income tax purposes. Deferred tax assets have been recorded for tax attributes contributed to the Company as part of the reorganization. Deferred tax liabilities of$29.3 million were recorded relating to the Liberty LLC Units acquired through the Corporate Reorganization. The effective combinedU.S. federal and state income tax rate applicable to the Company for the year endedDecember 31, 2019 and 2018 was 15.8% and 14.0%, respectively. The Company's effective tax rate is significantly less than the federal statutory income tax rate of 21.0% primarily because no taxes are payable by the Company for the non-controlling interest's share ofLiberty LLC's pass-through income for federal, state and local income tax reporting. The Company recognized income tax expense of$14.1 million and$40.4 million for the year endedDecember 31, 2019 and 2018, respectively. Critical Accounting Policies and Estimates The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations. We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our combined financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our combined financial statements and related notes included in "Item 8. Financial Statements and Supplementary Data." Revenue Recognition: Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements. If our assessment of performance under a particular contract changes, our revenue and / or costs under that contract may change. In connection with ASC Topic 842, the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and service component for certain of the Company's service contracts when the service component is the predominant component and continues to account for the combined component under ASC Topic 606, Revenue from Contracts with Customers. Accounts Receivable: We analyze the need for an allowance for doubtful accounts for estimated losses related to potentially uncollectible accounts receivable on a case-by-case basis throughout the year. We reserve amounts based on specific identification after considering each customer's situation, including payment patterns, current financial condition as well as general economic conditions. It is reasonably possible that our estimates of the allowance for doubtful accounts will change and that losses ultimately incurred could differ materially from the amounts estimated in determining the allowance. Inventory: Inventory consists of raw materials used in the hydraulic fracturing process, such as proppants, chemicals and field service equipment maintenance parts, and is stated at the lower of cost or net realizable value, determined using the weighted average cost method. Net realizable value is determined based on our estimates of selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment. Property and Equipment: We calculate depreciation and amortization on our assets based on the estimated useful lives and estimated salvage values that we believe are reasonable. The estimated useful lives and salvage values are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. We incur maintenance costs on our major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs benefit future periods, relative to our capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. Impairment of long-lived and other intangible assets: Long-lived assets, such as property and equipment and finite-lived intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. When alternative 52 -------------------------------------------------------------------------------- Table of Contents courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence, which require us to apply judgment. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. No events or changes in circumstances occurred that would indicate a potential impairment of property and equipment as ofDecember 31, 2019 and 2018. No impairment was recognized during the years endedDecember 31, 2019 , 2018 and 2017. Leases: The Company adopted Accounting Standards Update ("ASU") No. 2016-02, Leases ASC Topic 842 effectiveJanuary 1, 2019 . We elected the modified retrospective transition method under ASC Topic 842 and as such information prior toJanuary 1, 2019 has not been restated and continues to be reported under the accounting standards in effect for the period (ASC Topic 840). We carried forward the historical lease classifications and assessment of initial direct costs, account for lease and non-lease components as a single component, and exclude leases with an initial term of less than 12 months in the lease assets and liabilities. For leases entered into afterJanuary 1, 2019 , the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew; however, we typically cannot determine our intent to renew a lease with reasonable certainty at inception. Tax Receivable Agreements: In connection with the IPO, onJanuary 17, 2018 , the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, inU.S. federal, state, and local income tax and franchise tax that the Company actually realizes in periods after the IPO as a result of certain tax attributes applicable to each TRA Holder. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies. Share Repurchases: The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. Recent Accounting Pronouncements See Note 2-Significant Accounting Policies-Recently Issued Accounting Standards to the consolidated and combined financial statements included in "Item 8. Financial Statements and Supplementary Data" for a discussion of recent accounting pronouncements. Off Balance Sheet Arrangements We have no material off balance sheet arrangements as ofDecember 31, 2019 , except for purchase commitments under supply agreements as disclosed above under "-Contractual Obligations." As such, we are not materially exposed to any other financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements. 53
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