DIAMONDBACK ENERGY, INC. 
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto 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. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See Item 1A. "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements." Overview We operate in two business segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in thePermian Basin inWest Texas and (ii) through our subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in theMidland and Delaware Basins of thePermian Basin .
Upstream Operations
In our upstream segment, our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in theMidland Basin and the Wolfcamp and Bone Spring formations in theDelaware Basin . We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. As ofDecember 31, 2019 , we had approximately 382,337 net acres, which primarily consisted of approximately 195,461 net acres in theMidland Basin and approximately 155,296 net acres in theDelaware Basin . As ofDecember 31, 2019 , we had an estimated 12,310 gross horizontal locations that we believe to be economic at$60.00 per Bbl West Texas Intermediate, or WTI. In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 814,224 gross acres and 24,304 net royalty acres in thePermian Basin andEagle Ford Shale . Approximately 50% of these net royalty acres are operated by us. We own Viper's general partner and, together with one of our subsidiaries, approximately 58% of the limited partner interest in Viper, represented by common units and Class B units. We, as the holder of the Class B units in Viper and Viper's general partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective capital contributions payable quarterly.
Midstream Operations
In our midstream operations segment, Rattler's crude oil infrastructure assets consist of gathering pipelines and metering facilities, which collectively gather crude oil for its customers. Rattler's facilities gather crude oil from horizontal and vertical wells in our ReWard,Spanish Trail ,Pecos and Fivestones areas within thePermian Basin . Rattler's natural gas gathering and compression system consists of gathering pipelines, compression and metering facilities, which collectively service the production from ourPecos area assets within thePermian Basin . Rattler's water sourcing and distribution assets consists of water wells, frac pits, pipelines and water treatment facilities, which collectively gather and distribute water fromPermian Basin aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Rattler's gathering and disposal system spans approximately 474 miles and consists of gathering pipelines along with produced water disposal, or PWD, wells and facilities which collectively gather and dispose of produced water from operations throughout ourPermian Basin acreage. We have entered into multiple fee-based commercial agreements with Rattler, each with an initial term ending in 2034, utilizing Rattler's infrastructure assets or its planned infrastructure assets to provide an array of essential services critical to our upstream operations in theDelaware and Midland Basins. Our agreements with Rattler include substantial acreage dedications. 58
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2019 Transactions and Recent Developments
Rattler Midstream LP
Rattler is a publicly tradedDelaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol "RTLR". Rattler was formed by us inJuly 2018 to own, operate, develop and acquire midstream infrastructure assets in theMidland and Delaware Basins of thePermian Basin .Rattler Midstream GP LLC , or Rattler'sGeneral Partner , a wholly-owned subsidiary of us, serves as the general partner of Rattler. As ofDecember 31, 2019 , we owned approximately 71% of Rattler's total units outstanding. InMay 2019 , Rattler completed its initial public offering, which we refer to as the Rattler Offering. Prior to the completion of the Rattler Offering, we owned all of the general and limited partner interests in Rattler. The Rattler Offering consisted of an aggregate of 43,700,000 common units representing approximately 29% of the limited partner interests in Rattler at a price to the public of$17.50 per common unit, which included 5,700,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms which closed onMay 30, 2019 . Rattler received net proceeds of approximately$720 million from the sale of these common units, after deducting offering expenses and underwriting discounts and commissions. In connection with the completion of the Rattler Offering, Rattler (i) issued 107,815,152 Class B units representing an aggregate 71% voting limited partner interest in Rattler in exchange for a$1 million cash contribution from us, (ii) issued a general partner interest in Rattler to Rattler's general partner, in exchange for a$1 million cash contribution from Rattler's general partner, and (iii) causedRattler LLC to make a distribution of approximately$727 million to us. We, as the beneficial holder of the Class B units, and Rattler's general partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective$1 million capital contributions, payable quarterly.
Fourth Quarter 2019 Dividend Declaration and Increase
OnFebruary 14, 2020 , our board of directors declared a cash dividend for the fourth quarter of 2019 of$0.3750 per share of common stock, payable onMarch 10, 2020 to our stockholders of record at the close of business onMarch 3, 2020 , representing an increase of$0.1875 per share from the previously paid quarterly dividend. Stock Repurchase Program InMay 2019 , our board of directors approved a stock repurchase program to acquire up to$2 billion of our outstanding common stock throughDecember 31, 2020 . This repurchase program is another component of our capital return program that includes the quarterly dividend discussed above. We anticipate that the repurchase program will be funded primarily by free cash flow generated from operations and liquidity events such as the sale of assets. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require us to acquire any specific number of shares. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the year endedDecember 31, 2019 , we repurchased approximately$598 million of common stock under our repurchase program. As ofDecember 31, 2019 ,$1.4 billion remains available for use to repurchase shares under our common stock repurchase program.
Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen
On
OnJuly 1, 2019 , we completed our divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which we acquired in the Energen merger, for an aggregate sale price of$285 million . This divestiture did not result in a gain or loss because it did not have a significant effect on our reserve base or depreciation, depletion and amortization rate.
Viper's Equity Offering
OnMarch 1, 2019 , Viper completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, we owned approximately 54% of Viper's total units then outstanding. Viper received net proceeds from this offering 59
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of approximately$341 million , after deducting underwriting discounts and commissions and estimated offering expenses. Viper used the net proceeds to purchase units ofViper LLC .Viper LLC in turn used the net proceeds to repay a portion of the outstanding borrowings under its revolving credit facility and finance acquisitions during the period.
Drop-Down
OnOctober 1, 2019 , we completed a transaction to divest certain mineral and royalty interests to Viper for 18.3 million of Viper's newly-issued Class B units, 18.3 million newly-issued units ofViper LLC with a fair value of$497 million and$190 million in cash, after giving effect to closing adjustments for net title benefits, which we refer to as the Drop-Down. The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across theMidland and Delaware Basins, of which over 95% are operated by us, and have an average net royalty interest of approximately 3.2%. Increase in the Borrowing Base underViper LLC's Revolving Credit Facility
In connection with
Viper's Notes Offering OnOctober 16, 2019 , Viper completed an offering, which we refer to as the Viper Notes Offering, of$500 million in aggregate principal amount of its 5.375% senior notes due 2027, which we refer to as the Viper Notes. Viper received net proceeds of approximately$490 million from the Viper Notes Offering. Viper loaned the gross proceeds toViper LLC .Viper LLC used the proceeds from the Viper Notes Offering to pay down borrowings under its revolving credit facility.
OnDecember 5, 2019 , we issued$1.0 billion in aggregate principal amount of 2.875% senior notes due 2024, which we refer to as the 2024 notes,$800 million in aggregate principal amount of 3.250% senior notes due 2026, which we refer to as the 2026 notes, and$1.2 billion aggregate principal amount of 3.500% senior notes due 2029, which we refer to as the 2029 notes and, together with the 2024 notes and the 2026 notes, theDecember 2019 Notes. The 2024 notes will mature onDecember 1, 2024 , the 2026 notes will mature onDecember 1, 2026 and the 2029 notes will mature onDecember 1, 2029 . Interest will accrue and be payable semi-annually, in arrears onJune 1 andDecember 1 of each year, commencing onJune 1, 2020 . TheDecember 2019 Notes are fully and unconditionally guaranteed byDiamondback O&G LLC .
Redemption of the Outstanding 4.750% Senior Notes.
On
Operational Update
Our development program is focused entirely within thePermian Basin , where we continue to focus on long-lateral multi-well pad development. Our horizontal development consists of multiple targeted intervals, primarily within the Wolfcamp and Spraberry formations in theMidland Basin and the Wolfcamp andBone Springs formations in theDelaware Basin . We are operating 23 drilling rigs now including two rigs drilling produced water disposal wells and currently intend to operate between 20 and 23 drilling rigs in 2020 on average across our asset base in theMidland and Delaware Basins.
In the
In theDelaware Basin , we have now drilled and completed a significant number of wells inPecos ,Reeves andWard counties targeting the Wolfcamp A, which we believe has been de-risked across a significant portion of our total acreage position and remains our primary development target. In 2020, we expect to focus development on these areas. We continue to focus on low cost operations and best in class execution. To combat potential fluctuation in service costs, we have looked to lock in pricing for dedicated activity levels and will continue to seek opportunities to control additional well cost where possible. Our 2020 drilling and completion budget accounts for capital costs that we believe cover potential increases in our service costs during the year. 60
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In 2020, we remain focused on navigating our industry challenges by staying disciplined, improving our industry-leading cost structure, growing production, increasing environmental transparency and returning more cash to our stockholders as evidenced by our quarterly dividend increase beginning with the fourth quarter of 2019. 2020 Capital Budget We have currently budgeted a 2020 total capital spend of$2.8 billion to$3.0 billion , consisting of$2.45 billion to$2.6 billion for horizontal drilling and completions including non-operated activity,$200 million to$225 million for midstream investments, excluding joint venture investments, and$150 million to$175 million for infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions. We expect to drill and complete 320 to 360 gross horizontal wells in 2020. Should commodity prices weaken further or remain weak for an extended period of time, we intend to act responsibly and, consistent with our prior practices, reduce capital spending. If commodity prices strengthen, we intend to grow oil production within our 2020 budget and return cash to our stockholders or pay down indebtedness.
Reserves and pricing
Ryder Scott prepared estimates of our proved reserves atDecember 31, 2019 and 2018 (which include estimated proved reserves attributable to Viper). The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2019 2018 Estimated Net Proved Reserves: Oil (MBbls) 710,903 626,936 Natural gas (MMcf) 1,118,811 1,048,649 Natural gas liquids (MBbls) 230,203 190,291 Total (MBOE) 1,127,575 992,001 Unweighted Arithmetic Average First-Day-of-the-Month Prices 2019 2018 Oil (per Bbl) $ 51.88$ 59.63 Natural gas (per Mcf) $ 0.18$ 1.47 Natural gas liquids (per Bbl) $ 15.65$ 24.43
Sources of our revenue
In our upstream segment, our main sources of revenues are the sale of oil and
natural gas production, as well as the sale of natural gas liquids that are
extracted from our natural gas during processing.
In our midstream operations segment, our results are primarily driven by: the
volumes of crude oil that Rattler gathers, transports and delivers; natural gas
that Rattler gathers, compresses, transports and delivers; water that Rattler
sources, transports and delivers; and produced water that Rattler gathers,
transports and disposes of, and the fees Rattler charges per unit of throughput
for our midstream services.
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The following table presents the sources of our oil and natural gas revenues for
the years presented:
Year Ended December 31,
2019 2018
Revenues:
Oil sales 91 % 88 %
Natural gas sales 2 % 3 %
Natural gas liquid sales 7 % 9 %
100 % 100 %
Commodity Prices
Since our production, in our exploration and production business, consists
primarily of oil, our revenues are more sensitive to fluctuations in oil prices
than they are to fluctuations in natural gas or natural gas liquids prices.
Viper, as the owner of mineral interests, is also indirectly exposed to
fluctuations in commodity prices. Oil, natural gas and natural gas liquids
prices have historically been volatile. Lower commodity prices may not only
decrease our revenues, but also potentially the amount of oil and natural gas
that we can produce economically. Lower oil and natural gas prices may also
result in a reduction in the borrowing base under our credit agreement, which
may be redetermined at the discretion of our lenders.
In our midstream operations business, we have indirect exposure to commodity
price risk in that persistent low commodity prices may cause us or Rattler's
other customers to delay drilling or shut in production, which would reduce the
volumes available for gathering and processing by our infrastructure assets. If
we or Rattler's other customers delay drilling or temporarily shut in production
due to persistently low commodity prices or for any other reason, our revenue in
the midstream operations segment could decrease, as Rattler's commercial
agreements do not contain minimum volume commitments.
The following table sets forth information related to commodity prices for the
following periods:
Year Ended December 31,
2019 2018
High and Low Futures Contract Prices:
Oil ($/Bbl, WTI Futures Contract 1)
High $ 66.30 $ 76.41
Low $ 46.54 $ 42.53
Natural Gas ($/MMBtu, Futures Contract 1)
High $ 3.59 $ 4.84
Low $ 2.07 $ 2.55
Average realized oil price ($/Bbl) $ 51.87 $ 54.66
Average WTI Futures Contract 1 ($/Bbl) $ 57.04 $ 64.90
Differential to WTI Futures Contract 1 $ (5.17 ) $ (10.24 )
Average realized oil price to WTI Futures Contract 1 91 % 84 %
Average realized natural gas price ($/Mcf) $ 0.68 $ 1.76
Average Natural Gas Futures Contract 1 ($/Mcf) $ 2.53 $ 3.07
Differential to Natural Gas Futures Contract 1 $ (1.85 )
27 % 57 %
Average realized natural gas liquids price ($/Bbl)
$ 25.47 Average WTI Futures Contract 1 ($/Bbl)$ 57.04 $ 64.90 Average realized natural gas liquids price to WTI Futures Contract 1 25 % 39 %
On
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Principal components of our cost structure
Lease operating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties. Production and ad valorem taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.
General and administrative expenses. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.
Midstream services expense. These are costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.
Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.
Impairment of oil and natural gas properties. This is the cost to reduce proved oil and gas properties to the calculated full cost ceiling value.
Other income (expense)
Interest income (expense). We have financed a portion of our working capital
requirements, capital expenditures and acquisitions with borrowings under our
revolving credit facility and our net proceeds from the issuance of the senior
notes. We incur interest expense that is affected by both fluctuations in
interest rates and our financing decisions. This amount reflects interest paid
to our lender plus the amortization of deferred financing costs (including
origination and amendment fees), commitment fees and annual agency fees net of
interest received on our cash and cash equivalents.
Gain (loss) on derivative instruments, net. We utilize commodity derivative
financial instruments to reduce our exposure to fluctuations in the price of
crude oil. This amount represents (i) the recognition of the change in the fair
value of open non-hedge derivative contracts as commodity prices change and
commodity derivative contracts expire or new ones are entered into, and (ii) our
gains and losses on the settlement of these commodity derivative instruments.
Deferred tax assets (liabilities). We use the asset and liability method of
accounting for income taxes, under which deferred tax assets and liabilities are
recognized for the future tax consequences of (1) temporary differences between
the financial statement carrying amounts and the tax bases of existing assets
and liabilities and (2) operating loss and tax credit carryforwards. Deferred
income tax assets and liabilities are based on enacted tax rates applicable to
the future period when those temporary differences are expected to be recovered
or settled. The effect of a change in tax rates on deferred tax assets and
liabilities is recognized in income in the period the rate change is enacted. A
valuation allowance is provided for deferred tax assets when it is more likely
than not the deferred tax assets will not be realized.
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Results of Operations
For a discussion of the results of operations for the year endedDecember 31, 2018 as compared to the year endedDecember 31, 2017 refer to Part II, Item 7. Management's Discussion and Analysis in our 2018 Form 10-K, which was filed with theSEC onFebruary 25, 2019 , which discussion is incorporated in this report by reference from such prior report on Form 10-K. The following table sets forth selected historical operating data for the periods indicated: Year Ended December 31, 2019 2018 Production Data: Oil (MBbls) 68,518 34,367 Natural gas (MMcf) 97,613 34,669 Natural gas liquids (MBbls) 18,498 7,465 Combined volumes (MBOE) 103,285 47,610 Daily oil volumes (BO/d) 187,721 94,156 Daily combined volumes (BOE/d) 282,972 130,439 Average Prices: Oil ($ per Bbl)$ 51.87 $ 54.66 Natural gas ($ per Mcf)$ 0.68 $ 1.76 Natural gas liquids ($ per Bbl)$ 14.42 $ 25.47 Combined ($ per BOE)$ 37.63 $ 44.73 Oil, hedged ($ per Bbl)(1)$ 51.96 $ 51.20 Natural gas, hedged ($ per MMbtu)(1)$ 0.86 $
1.72
Natural gas liquids, hedged ($ per Bbl)(1)$ 15.20 $
25.46
Average price, hedged ($ per BOE)(1)$ 38.00 $
42.20
(1) Hedged prices reflect the effect of our commodity derivative transactions on
our average sales prices. Our calculation of such effects include realized
gains and losses on cash settlements for commodity derivatives, which we do
not designate for hedge accounting.
Production Data
Substantially all of our revenues are generated through the sale of oil, natural
gas liquids and natural gas production. The following tables set forth our
production data for the years ended
Year Ended December 31,
2019 2018
Oil (MBbls) 66 % 72 %
Natural gas (MMcf) 16 % 12 %
Natural gas liquids (MBbls) 18 % 16 %
100 % 100 %
Comparison of the Years Ended
Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately$1.8 billion , or 82%, to$3.9 billion for the year endedDecember 31, 2019 from$2.1 billion for the year endedDecember 31, 2018 . Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 152,533 BOE/d to 282,972 BOE/d during the year endedDecember 31, 2019 from 130,439 BOE/d during the year endedDecember 31, 2018 . The total increase in revenue of approximately$1.8 billion is attributable to higher oil, natural gas liquids and natural gas production volumes, partially offset by lower average sales prices for the year endedDecember 31, 2019 as compared to the year endedDecember 31, 2018 . The increase in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our 64
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production increased by 34,151 MBbls of oil, 62,944 MMcf of natural gas and
11,033 MBbls of natural gas liquids for the year ended
The net dollar effect of the change in prices of approximately$501 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the change in production of approximately$2.3 billion (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below. Production Total net dollar Change in prices volumes(1) effect of change (in millions) Effect of changes in price: Oil$ (2.79 ) 68,518 $ (191 ) Natural gas$ (1.08 ) 97,613 $ (106 ) Natural gas liquids$ (11.05 ) 18,498 $ (204 ) Total revenues due to change in price $ (501 ) Change in production Prior period Total net dollar volumes(1)
average prices effect of change
(in millions)
Effect of changes in production volumes:
Oil 34,151 $ 54.66 $ 1,867
Natural gas 62,944 $ 1.76 $ 110
Natural gas liquids 11,033 $ 25.47 $ 281
Total change in revenues $ 2,258
$ 1,757
(1) Production volumes are presented in MBbls for oil and natural gas liquids and
MMcf for natural gas.
Lease Bonus Revenue. The following table shows lease bonus revenue for the years
ended
Year Ended December 31,
2019 2018
(in millions)
Lease bonus revenue $ 4 $ 3
Lease bonus revenue for the year ended December 31, 2019 was attributable to
lease bonus payments of less than $1 million to extend the term of seven leases
and lease bonus payments of $3 million on 12 new leases. Lease bonus revenue for
the year ended December 31, 2018 was attributable to lease bonus payments of $1
million to extend the term of two leases and lease bonus payments of $2 million
on five new leases.
Midstream Services Revenue. The following table shows midstream services revenue
for the years ended
Year Ended December 31,
2019 2018
(in millions)
Midstream services revenue $ 64 $ 34
Our midstream services revenue represents fees charged to our joint interest
owners and third parties for the transportation of oil and natural gas along
with water gathering and related disposal facilities. These assets complement
our operations in areas where we have significant production.
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Lease Operating Expenses. The following table shows lease operating expenses for
the years ended
Year Ended December 31,
2019 2018
(in millions, except per BOE amounts) Amount Per BOE Amount Per BOE Lease operating expenses
$ 490 $ 4.74 $ 205 $ 4.31 Lease operating expenses for the year endedDecember 31, 2019 as compared to the year endedDecember 31, 2018 increased by$285 million , or$0.43 per BOE. In both cases, lease operating expenses increased primarily due to increased power generation costs as a result of reduced electrical availability as well as increased production and the higher cost of the Central Basin Platform assets which were divested during 2019. We are actively working to mitigate this issue and expect these costs to decrease in the future.
Production and Ad Valorem Tax Expense. The following table shows production and
ad valorem tax expense for the years ended
Year Ended December 31,
2019 2018
(in millions, except per BOE amounts) Amount Per BOE Amount
Per BOE Production taxes$ 184 $ 1.78 $ 104 $ 2.18 Ad valorem taxes 64 0.62 29 0.61
Total production and ad valorem expense
In general, production taxes and ad valorem taxes are directly related to commodity price changes; however,Texas ad valorem taxes are based upon prior year commodity prices, among other factors, whereas production taxes are based upon current year commodity prices. Production taxes for the year endedDecember 31, 2019 as compared to the year endedDecember 31, 2018 increased by$80 million due to increased overall production from acquisitions and well completions. Production taxes per BOE for the year endedDecember 31, 2019 as compared to the year endedDecember 31, 2018 decreased by$0.40 primarily due to a higher percentage increase in production volumes as compared to production taxes. Ad valorem taxes for the year endedDecember 31, 2019 as compared to the year endedDecember 31, 2018 increased by$35 million due to the addition of acquired and completed wells from the latter half of 2019.
Midstream Services Expense. The following table shows midstream services expense
for the years ended
Year Ended December 31,
2019 2018
(in millions)
Midstream services expense $ 91 $ 72
Midstream services expense represents costs incurred to operate and maintain our
oil and natural gas gathering and transportation systems, natural gas lift,
compression infrastructure and water transportation facilities. Midstream
services expense for the year ended December 31, 2019 as compared to the year
ended December 31, 2018 , increased by $19 million primarily due to increased
volume and build out of the Rattler systems.
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Depreciation, Depletion and Amortization. The following table provides the
components of our depreciation, depletion and amortization expense for the years
ended
Year Ended December 31,
2019 2018
(in millions, except BOE
amounts)Depletion of proved oil and natural gas properties $ 1,398
$ 595 Depreciation of midstream assets 33 19 Depreciation of other property and equipment 16 9 Depreciation, depletion and amortization expense $ 1,447
$ 13.54 $ 12.62 The increase in depletion of proved oil and natural gas properties of
Impairment ofOil and Natural Gas Properties . The following table shows impairment of oil and natural gas properties for the years endedDecember 31, 2019 and 2018: Year EndedDecember 31, 2019 2018 (in millions) Impairment of oil and natural gas properties $ 790
$ -
General and Administrative Expenses. The following table shows general and
administrative expenses for the years ended
Year Ended December 31,
2019 2018
(in millions, except per BOE amounts) Amount Per BOE Amount Per BOE General and administrative expenses$ 56 $ 0.54 $ 38 $ 0.79 Non-cash stock-based compensation 48 0.46
27 0.57
Total general and administrative expenses
General and administrative expenses for the year ended
Net Interest Expense. The following table shows net interest expense for the
years ended
Year Ended December 31,
2019 2018
(in millions)
Net interest expense $ 172 $ 87
Net interest expense for the year ended December 31, 2019 as compared to the
year ended December 31, 2018 , increased by $85 million . This increase was
primarily due to increased average borrowings under our credit facility
partially offset by a lower interest rate during the year ended December 31,
2019 as compared to the year ended December 31, 2018 as well as an increase in
interest expense of $2 million related to our DrillCo Agreement.
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Derivatives. The following table shows the gain (loss) on derivative
instruments, net for the years ended
Year Ended December 31,
2019 2018
(in millions)
Change in fair value of open non-hedge derivative instruments
$ 222 Gain (loss) on settlement of non-hedge derivative instruments 80 (121 ) Gain (loss) on derivative instruments$ (108 )
We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned "Gain (loss) on derivative instruments, net."
Provision for Income Taxes. The following table shows provision for income taxes
for the years ended
Year Ended December 31,
2019 2018
(in millions)
Provision for income taxes $ 47 $ 168
The change in our income tax provision was primarily due to the decrease in
pre-tax income for the year ended December 31, 2019 and the change in the
deferred income tax benefit resulting from estimated deferred taxes recognized
as a result of Viper's change in tax status for the years ended December 31,
2019 and 2018.
Liquidity and Capital Resources
Historically, our primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of the senior notes and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. As we pursue reserves and production growth, we regularly consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us.
Liquidity and Cash Flow
Our cash flows for the years ended
Year Ended December 31,
2019 2018
(in millions)
Net cash provided by operating activities
2,041
Net change in cash $ (92 ) $ 103
Operating Activities
Net cash provided by operating activities was $2.7 billion for the year ended
December 31, 2019 as compared to $1.6 billion for the year ended December 31,
2018 . The increase in operating cash flows is primarily the result of an
increase in our oil and natural gas revenues due to an increase in production
during the year ended December 31, 2019 , partially offset by lower average sales
prices.
Our operating cash flow is sensitive to many variables, the most significant of
which is the volatility of prices for the oil and natural gas we produce. Prices
for these commodities are determined primarily by prevailing market conditions.
Regional
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and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. See "-Sources of our revenue" and Item 1A. "Risk Factors" above. Investing Activities The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. We used cash for investing activities of$3.9 billion and$3.5 billion during the years endedDecember 31, 2019 and 2018, respectively. During the year endedDecember 31, 2019 , we spent (a)$2.7 billion on capital expenditures in conjunction with our drilling program, in which we drilled 330 gross (296 net) horizontal wells and completed 317 gross (289 net) operated horizontal wells, (b)$244 million on additions to midstream assets, (c)$333 million for the acquisition of mineral interests, (d)$443 million on leasehold acquisitions, (e)$5 million for the purchase of other property and equipment, (f)$1 million on investment in real estate and (g)$485 million on equity method investments. During the year endedDecember 31, 2018 , we spent (a)$1.5 billion on capital expenditures in conjunction with our drilling program, in which we drilled 189 gross (168 net) horizontal wells and completed 176 gross (155 net) operated horizontal wells, (b)$204 million on additions to midstream assets, (c)$440 million for the acquisition of mineral interests, (d)$1.4 billion on leasehold acquisitions, (e)$7 million for the purchase of other property and equipment and (f)$111 million on investment in real estate.
Our investing activities for the years ended
Year Ended December 31,
2019 2018
(in thousands)
Drilling, completion and infrastructure
(244 ) (204 )
Acquisition of leasehold interests (443 ) (1,371 )
Acquisition of mineral interests (333 ) (440 )
Purchase of other property, equipment and land (5 ) (7 )
Investment in real estate (1 ) (111 )
Proceeds from sale of assets 300 80
Funds held in escrow - 11
Equity investments (485 ) -
Net cash used in investing activities
Financing Activities
References in this section to "us, "we" or "our" shall mean
Net cash provided by financing activities for the years ended
During the year endedDecember 31, 2019 , the amount provided by financing activities was primarily attributable to$341 million in net proceeds from Viper's public offering completed onMarch 1, 2019 ,$720 million in net proceeds from the Rattler Offering,$39 million in proceeds from joint ventures and$2.2 billion in proceeds from theDecember 2019 Notes, net of repayments, partially offset by$1.4 billion of repayments, net of borrowings under our credit facility,$44 million of premium on debt extinguishment,$122 million of distributions to non-controlling interest,$13 million of share repurchases for tax withholdings,$593 million of share repurchases as part of our stock repurchase program and$112 million of dividends to stockholders. During the year endedDecember 31, 2018 , the amount provided by financing activities was primarily attributable to the issuance of$1.1 billion of new senior notes,$1.4 billion of borrowings, net of repayments under our credit facility,$559 million of repayments under Energen's credit facility and an aggregate of$305 million of net proceeds from Viper's public offerings, partially offset by$98 million of distributions to non-controlling interest and$37 million of dividends to stockholders. 69
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Table of Contents 4.750% Senior Notes OnOctober 28, 2016 , we issued$500.0 million in aggregate principal amount of 4.750% senior notes due 2024 under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee. OnSeptember 25, 2018 , we issued$750 million aggregate principal amount of new 4.750% senior notes as additional notes under, and subject to the terms of the same indenture governing the 4.750% senior notes. We received approximately$741 million in net proceeds, after deducting the initial purchasers' discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the 4.750% senior notes. We used a portion of the net proceeds from the issuance of the 4.750% senior notes to repay a portion of the outstanding borrowings our revolving credit facility and the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of certain assets fromAjax Resources LLC . OnDecember 20, 2019 , we redeemed all of the outstanding 4.750% senior notes, which we refer to as the Redemption Date. The redemption payment, which we refer to the Redemption Payment, included$1.25 billion of outstanding principal at a redemption price of 103.563% of the principal amount of the 4.750% senior notes, plus accrued and unpaid interest on the outstanding principal amount to the Redemption Date. OnDecember 5, 2019 , the indenture governing the 4.750% senior notes was fully satisfied and discharged and the guarantors were released from their guarantees of the 4.750% senior notes. The 4.750% senior notes, which bore interest at 4.750% per year, were scheduled to mature onNovember 1, 2024 . On the Redemption Date, the Redemption Price will be paid to the holders of the 4.750% senior notes. We funded the Redemption Payment with a portion of our net proceeds from the issuance of theDecember 2019 Notes. The 4.750% senior notes, bore interest at a rate of 4.750% per annum, payable semi-annually, in arrears onMay 1 andNovember 1 of each year, commencing onMay 1, 2017 , and would have matured onNovember 1, 2024 . All of our restricted subsidiaries that guaranteed our revolving credit facility guaranteed the 4.750% senior notes; provided, however, that the 4.750% senior notes were not guaranteed by Viper, Viper'sGeneral Partner ,Viper LLC , Rattler, Rattler'sGeneral Partner orRattler LLC .
2025 Senior Notes
OnDecember 20, 2016 , we issued$500.0 million in aggregate principal amount of 5.375% senior notes due 2025, which we refer to as the exiting 2025 notes, under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, which we refer to as the 2025 indenture. OnJanuary 29, 2018 , we issued$300.0 million aggregate principal amount of new 5.375% senior notes due 2025 as additional notes under the 2025 indenture, which we refer to as the new 2025 notes and, together with the existing 2025 notes, as the 2025 senior notes. We received approximately$308.4 million in net proceeds, after deducting the initial purchaser's discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility. The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears onMay 31 andNovember 30 of each year and will mature onMay 31, 2025 . All of our existing and future restricted subsidiaries that guarantee our revolving credit facility guarantee the 2025 senior notes. Currently, the 2025 senior notes are not guaranteed by any of our subsidiaries other thanDiamondback O&G LLC and will not be guaranteed by any of our future unrestricted subsidiaries. For additional information regarding the 2025 senior notes, see Note 10-Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.December 2019 Notes Offering OnDecember 5, 2019 , we issued$1.0 billion in aggregate principal amount of 2.875% senior notes due 2024,$800 million in aggregate principal amount of 3.250% senior notes due 2026 and$1.2 billion aggregate principal amount of 3.500% senior notes due 2029. The 2024 notes will mature onDecember 1, 2024 , the 2026 notes will mature onDecember 1, 2026 and the 2029 notes will mature onDecember 1, 2029 . Interest will accrue and be payable semi-annually, in arrears onJune 1 andDecember 1 of each year, commencing onJune 1, 2020 . TheDecember 2019 notes are fully and unconditionally guaranteed byDiamondback O&G LLC and are not guaranteed by any of our other subsidiaries. TheDecember 2019 notes were issued under an indenture, dated as ofDecember 5, 2019 , among us andWells Fargo Bank , as the trustee, as supplemented by the first supplemental indenture dated as ofDecember 5, 2019 , which we refer to as theDecember 2019 Notes Indenture. TheDecember 2019 Notes Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of certain of our subsidiaries to incur liens 70
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securing funded indebtedness and on our ability to consolidate, merge or sell, convey, transfer or lease all or substantially all of our assets. For additional information regarding theDecember 2019 Notes, see Note 10-Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.
Second Amended and Restated Credit Facility
We and Diamondback O&G LLC , as borrower, entered into the second amended and restated credit agreement, datedNovember 1, 2013 , as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliateWells Fargo Securities, LLC , as sole book runner and lead arranger. OnJune 28, 2019 , the credit agreement was amended pursuant to an eleventh amendment, which implemented certain changes to the credit facility for the period on and after the date on which our unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied (the "investment grade changeover date"). AtDecember 31, 2019 , the maximum credit amount available under the credit agreement is$2.0 billion . As ofDecember 31, 2019 , we had approximately$13 million of outstanding borrowings under our revolving credit facility and$1.99 billion available for future borrowings under our revolving credit facility.Diamondback O&G LLC is the borrower under the credit agreement, and as ofDecember 31, 2019 , the credit agreement is guaranteed byDiamondback Energy, Inc. None of our other subsidiaries are guarantors under our revolving credit facility. OnDecember 5, 2019 ,Diamondback O&G LLC delivered a letter notifying the administrative agent under the credit agreement that as of such date, each of the guarantors, other thanDiamondback Energy, Inc. , ceased to be a guarantor under the credit agreement. The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.125% to 1.0% per annum and from 1.125% to 2.0% per annum in the case of LIBOR, in each case, depending on the pricing level, which in turn depends on the rating agencies' rating of our unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies' rating of our unsecured debt. Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage). Loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment due to any termination or reduction of the aggregate maximum credit amount and (b) at the maturity date ofNovember 1, 2022 . The credit agreement contains a financial covenant that requires us to maintain a total net debt to capitalization ratio (as defined in the credit agreement) of no more than 65%. Our non-guarantor restricted subsidiaries may incur debt for borrowed money in an aggregate principal amount up to 15% of consolidated net tangible assets (as defined in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets. As ofDecember 31, 2019 , we were in compliance with all financial covenants under our revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. Energen Notes At the effective time of the merger, Energen became our wholly owned subsidiary and remained the issuer of an aggregate principal amount of$530 million in notes, which we refer to as the Energen Notes, issued under an indenture datedSeptember 1, 1996 withThe Bank of New York as Trustee, which we refer to as the Energen Indenture. As ofDecember 31, 2019 , the Energen Notes consist of: (a)$399 million aggregate principal amount of 4.625% senior notes due onSeptember 1, 2021 , (2)$108 million of 7.125% notes due onFebruary 15, 2028 , (3)$21 million of 7.32% notes due onJuly 28, 2022 , and (4)$11 million of 7.35% notes due onJuly 28, 2027 . The Energen Notes are the senior unsecured obligations of Energen and, post-merger, Energen, as our wholly owned subsidiary, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen if any, and are effectively subordinated to Energen's senior secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness. Neither we nor any of our subsidiaries guarantee the Energen Notes. 71
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For additional information regarding the Energen Notes, See Note 10-Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.
Viper's
OnJuly 20, 2018 ,Viper LLC , as borrower, entered into an amended and restated credit agreement with Viper, as guarantor, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended, which we refer to as the Viper credit agreement, provides for a revolving credit facility in the maximum credit amount of$2 billion and a borrowing base based onViper LLC's oil and natural gas reserves and other factors (the "borrowing base") of$775 million , subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates ofMay 1st andNovember 1st . In addition,Viper LLC and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. In connection with Viper's fall redetermination inNovember 2019 , the borrowing base under the Viper credit agreement was increased to$775 million . As ofDecember 31, 2019 , the borrowing base was$775 million , andViper LLC had$97 million of outstanding borrowings and$678 million available for future borrowings under the Viper credit agreement. Neither we nor any of our other subsidiaries guarantee the Viper credit agreement. The outstanding borrowings under the Viper credit agreement bear interest at a per annum rate elected byViper LLC that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base.Viper LLC is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date ofNovember 1, 2022 . The loan is secured by substantially all of the assets ofViper and Viper LLC . The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below. Financial Covenant Required
Ratio
Ratio of total net debt to EBITDAX, as defined in the Viper Not greater than credit agreement
4.0 to 1.0
Ratio of current assets to liabilities, as defined in the Not less than 1.0 Viper credit agreement
to 1.0
The covenant prohibiting additional indebtedness allows for the issuance of
unsecured debt of up to $1.0 billion in the form of senior unsecured notes and,
in connection with any such issuance, the reduction of the borrowing base by 25%
of the stated principal amount of each such issuance. The covenant limiting
dividends and distributions includes an exception allowing Viper LLC to make
distributions if no default, event of default or borrowing base deficiency
exists.
As of December 31, 2019 , Viper and Viper LLC were in compliance with all
financial covenants under the Viper credit agreement, as then in effect. The
lenders may accelerate all of the indebtedness under the Viper credit agreement
upon the occurrence and during the continuance of any event of default. The
Viper credit agreement contains customary events of default, including
non-payment, breach of covenants, materially incorrect representations,
cross-default, bankruptcy and change of control.
Viper's Notes
OnOctober 16, 2019 , Viper completed an offering in which it issued its 5.375% Senior Notes due 2027 in aggregate principal amount of$500 million . Viper received gross proceeds of$500 million from the such offering, which it loaned toViper LLC .Viper LLC paid the expenses of the offering, resulting in net proceeds of the offering of$490 million , whichViper LLC used to pay down borrowings under the Viper credit agreement. 72
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The Viper Notes were issued under an indenture, dated as ofOctober 16, 2019 , among Viper, as issuer,Viper LLC , as guarantor and Wells Fargo, as trustee, which we refer to as the Viper Indenture. Pursuant to the Viper Indenture and the Viper Notes, interest on the Viper Notes accrues at a rate of 5.375% per annum on the outstanding principal amount thereof, payable semi-annually onMay 1 andNovember 1 of each year, commencing onMay 1, 2020 . The Viper Notes will mature onNovember 1, 2027 .
The Viper Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Viper's ability and the ability of its restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events. Rattler's Credit Agreement In connection with the Rattler Offering, Rattler, as parent, andRattler LLC , as borrower, entered into a credit agreement, datedMay 28, 2019 , withWells Fargo Bank , as administrative agent, and a syndicate of banks, as lenders party thereto, which we refer to as the Rattler credit agreement. The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of$600 million . Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be prepaid at the maturity date ofMay 28, 2024 . The Rattler credit agreement is guaranteed byRattler, Tall City, Rattler OMOG LLC andRattler Ajax Processing LLC and is secured by substantially all of the assets ofRattler LLC, Rattler, Tall City, Rattler OMOG LLC andRattler Ajax Processing LLC . As ofDecember 31, 2019 ,Rattler LLC had$424 million of outstanding borrowings and$176 million available for future borrowings under the Rattler credit agreement. The outstanding borrowings under the Rattler credit agreement bear interest at a per annum rate elected byRattler LLC that is based on the prime rate or LIBOR, in each case plus an applicable margin. The applicable margin ranges from 0.250% to 1.250% per annum for prime-based loans and 1.250% to 2.250% per annum for LIBOR loans, in each case depending on the Consolidated Total Leverage Ratio (as defined in the Rattler credit agreement).Rattler LLC is obligated to pay a quarterly commitment fee ranging from 0.250% to 0.375% per annum on the unused portion of the commitment, which fee is also dependent on the Consolidated Total Leverage Ratio. The Rattler credit agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, distributions and other restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case of Rattler,Rattler LLC and their restricted subsidiaries. The covenants are subject to exceptions set forth in the Rattler credit agreement, including an exception allowingRattler LLC or Rattler to issue unsecured debt securities and an exception allowing payment of distributions if no default or events of default exists. 73
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The Rattler credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below: Financial Covenant
Required Ratio
Consolidated Total Leverage Ratio Not greater than 5.00 to
1.00 (or not greater than
5.50 to 1.00 for 3 fiscal
quarters following certain
acquisitions), but if the
Consolidated Senior Secured
Leverage Ratio (as defined
in the Rattler credit
agreement) is applicable,
then not greater than 5.25
to 1.00)
Consolidated Senior Secured Leverage Ratio
commencing with the last day of any fiscal quarter
in which the Financial Covenant Election (as defined Not greater than 3.50 to
in the Rattler credit agreement) is made 1.00
Consolidated Interest Coverage Ratio (as defined in the Rattler credit agreement)
Not less than 2.50 to 1.00
For purposes of calculating the financial maintenance covenants prior to the fiscal quarter endingJune 30, 2020 , EBITDA (as defined in the Rattler credit agreement) will be annualized based on the actual EBITDA for the preceding fiscal quarters starting with the fiscal quarter endingSeptember 30, 2019 . As ofDecember 31, 2019 ,Rattler and Rattler LLC were in compliance with all financial covenants under the Rattler credit agreement. The lenders may accelerate all of the indebtedness under the Rattler credit agreement upon the occurrence and during the continuance of any event of default. The Rattler credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control.
Capital Requirements and Sources of Liquidity
Our board of directors approved a 2020 capital budget for drilling, midstream and infrastructure of$2.8 billion to$3.0 billion , representing an increase of 1% over our 2019 capital budget. We estimate that, of these expenditures, approximately:
•
to 360 gross (288 to 324 net) horizontal wells across our operated
leasehold acreage in the
with an average lateral length of approximately 9,700 feet;
•
excluding joint venture investments; and
• $150 million to $175 million will be spent on infrastructure and otherexpenditures, excluding the cost of any leasehold and mineral interest
acquisitions.
During the year ended December 31, 2019 , our aggregate capital expenditures for
drilling and infrastructure were $2.7 billion . We do not have a specific
acquisition budget since the timing and size of acquisitions cannot be
accurately forecasted. During the year ended December 31, 2019 , we spent
approximately $443 million in cash on acquisitions of leasehold interests and
mineral acres.
In May 2019 , our board of directors approved a stock repurchase program to
acquire up to $2 billion of our outstanding common stock through December 31,
2020 . We repurchased approximately $598 million of our common stock under this
program during the year ended December 31, 2019 , with approximately $1.4 billion
remaining available for future repurchases under this program. We intend to
continue to purchase shares under the repurchase program opportunistically with
available funds primarily from cash flow from operations and liquidity events
such as the sale of assets while maintaining sufficient liquidity to fund our
capital expenditure programs.
The amount and timing of our capital expenditures are largely discretionary and
within our control. We could choose to defer a portion of these planned capital
expenditures depending on a variety of factors, including but not limited to the
success of our drilling activities, prevailing and anticipated prices for oil
and natural gas, the availability of necessary equipment, infrastructure and
capital, the receipt and timing of required regulatory permits and approvals,
seasonal conditions, drilling and acquisition costs and the level of
participation by other interest owners. We are currently operating 23 drilling
rigs including two rigs drilling produced water disposal wells and nine
completion crews. We will continue monitoring commodity prices and overall
market conditions and can adjust our rig cadence up or down in response to
changes in commodity prices and overall market conditions.
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Based upon current oil and natural gas prices and production expectations for 2020, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2020. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2020 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions. We monitor and adjust our projected capital expenditures in response to the results of our drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. If there is a decline in commodity prices, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected. Contractual Obligations The following table summarizes our contractual obligations and commitments as ofDecember 31, 2019 : Payments Due by Period 2020 2021-2022 2023-2024 Thereafter Total (in millions) Secured revolving credit facility(1) $ -$ 13 $ - $ -$ 13 Commitment fees related to the secured revolving credit facility(2) 2 5 - - 7 Senior notes - 420 1,000 2,919 4,339 Interest expense related to the senior notes(3) 168 311 294 301 1,074 DrillCo Agreement - - - 39 39 Viper's secured revolving credit facility(1) - 97 - - 97 Commitment fees under Viper's credit agreement(4) 3 4 - - 7 Viper's senior notes - - - 500 500 Interest expense related to Viper's senior notes 27 54 54 76 211 Rattler's secured revolving credit facility(1) - - 424 - 424 Commitment fees under Rattler's credit agreement(5) - 1 1 - 2 Asset retirement obligations(6) - - - 94 94 Drilling commitments(7) 15 - - - 15 Sand supply agreements 18 36 36 23 113 Operating lease obligations(8) 11 14 7 5 37$ 244 $ 955 $ 1,816 $ 3,957 $ 6,972
(1) Includes the outstanding principal amount under the revolving credit
facilities, the table does not include interest expense or other fees payable
under this floating rate facility as we cannot predict the timing of future
borrowings and repayments or interest rates to be charged.
(2) Includes only the minimum amount of commitment fees due which, as of
unused portion of the borrowing base of the Company's credit agreement.
(3) Interest represents the scheduled cash payments on the senior notes and
Energen Notes.
(4) Includes only the minimum amount of commitment fees due which, as of
unused portion of the borrowing base of Viper's credit agreement.
(5) Includes only the minimum amount of commitment fees due which, as of
unused portion of the borrowing base of Rattler's credit agreement.
(6) Amounts represent our estimates of future asset retirement obligations.
Because these costs typically extend many years into the future, estimating
these future costs requires management to make estimates and judgments that
are subject to future revisions based upon numerous factors, including the
rate of inflation, changing technology and the political and regulatory
environment. See Note 8-Asset Retirement Obligations of the Notes to the
Consolidated Financial Statements included elsewhere in this Form 10-K.
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(7) Drilling commitments represent future minimum expenditure commitments for
drilling rig services under contracts to which the Company was a party on
(8) Operating lease obligations represent future commitments for building,
equipment and vehicle leases.
The table above does not include estimated deficiency fees related to certain volume commitments that we have as they are based off future volume deliveries and differences from market pricing which we cannot predict.
Critical Accounting Policies
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted inthe United States . Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2-Summary of Significant Accounting Policies of the Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.
Use of Estimates
Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates. We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.
Method of accounting for oil and natural gas properties
We account for our oil and natural gas producing activities using the full cost
method of accounting. Accordingly, all costs incurred in the acquisition,
exploration and development of proved oil and natural gas properties, including
the costs of abandoned properties, dry holes, geophysical costs and annual lease
rentals are capitalized. We also capitalize direct operating costs for services
performed with internally owned drilling and well servicing equipment. Internal
costs capitalized to the full cost pool represent management's estimate of costs
incurred directly related to exploration and development activities such as
geological and other administrative costs associated with overseeing the
exploration and development activities. All internal costs unrelated to drilling
activities are expensed as incurred. Sales or other dispositions of oil and
natural gas properties are accounted for as adjustments to capitalized costs,
with no gain or loss recorded unless the ratio of cost to proved reserves would
significantly change. Income from services provided to working interest owners
of properties in which we also own an interest, to the extent they exceed
related costs incurred, are accounted for as reductions of capitalized costs of
oil and natural gas properties. Depletion of evaluated oil and natural gas
properties is computed on the units of production method, whereby capitalized
costs plus estimated future development costs are amortized over total proved
reserves.
Costs associated with unevaluated properties are excluded from the full cost
pool until we have made a determination as to the existence of proved reserves.
We assess all items classified as unevaluated property on an annual basis for
possible impairment. We assess properties on an individual basis or as a group
if properties are individually insignificant. The assessment includes
consideration of the following factors, among others: intent to drill; remaining
lease term; geological and geophysical evaluations; drilling results and
activity; the assignment of proved reserves; and the economic viability of
development if proved reserves are assigned. During any period in which these
factors indicate an impairment, the cumulative drilling costs incurred to date
for such property and all or a portion of the associated leasehold costs are
transferred to the full cost pool and are then subject to amortization.
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Oil and natural gas reserve quantities and standardized measure of future net revenue
Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. TheSEC has defined proved reserves as the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Revenue recognition
Revenue from Contracts with Customers
Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in our contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.
Oil sales
Our oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, we or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in our consolidated statements of operations.
Natural gas and natural gas liquids sales
Under our natural gas processing contracts, it delivers natural gas to a
midstream processing entity at the wellhead, battery facilities or the inlet of
the midstream processing entity's system. The midstream processing entity
gathers and processes the natural gas and remits proceeds to us for the
resulting sales of natural gas liquids and residue gas. In these scenarios, we
evaluate whether it is the principal or the agent in the transaction. For those
contracts where we have concluded it is the principal and the ultimate third
party is its customer, we recognize revenue on a gross basis, with
transportation, gathering, processing, treating and compression fees presented
as an expense in our consolidated statements of operations.
In certain natural gas processing agreements, we may elect to take its residue
gas and/or natural gas liquids in-kind at the tailgate of the midstream entity's
processing plant and subsequently market the product. Through the marketing
process, we deliver product to the ultimate third-party purchaser at a
contractually agreed-upon delivery point and receives a specified index price
from the purchaser. In this scenario, we recognize revenue when control
transfers to the purchaser at the delivery point based on the index price
received from the purchaser. The gathering, processing, treating and compression
fees attributable to the gas processing contract, as well as any transportation
fees incurred to deliver the product to the purchaser, are presented as
transportation, gathering, processing, treating and compression expense in our
consolidated statements of operations.
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Midstream Revenue
Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler provides to exploration and production operations. The portion of such fees shown in our consolidated financial statements represent amounts charged to interest owners in our operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler's gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of our facilities. For services contracted through third party providers, Rattler's performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement.
Transaction price allocated to remaining performance obligations
Our upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days' production. Therefore, there are no remaining performance obligations under any of our product sales contracts. The majority of our midstream revenue agreements have a term greater than one year, and as such we have utilized the practical expedient in ASC 606, which states that we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The remainder of our midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. We have utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less.
Contract balances
Under our product sales contracts, we have the right to invoice our customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC 606.
Prior-period performance obligations
We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the year endedDecember 31, 2019 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. We believe that the pricing provisions of our oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.
Impairment
We use the full cost method of accounting for our oil and natural gas
properties. Under this method, all acquisition, exploration and development
costs, including certain internal costs, are capitalized and amortized on a
composite unit of production method based on proved oil, natural gas liquids and
natural gas reserves. Internal costs capitalized to the full cost pool represent
management's estimate of costs incurred directly related to exploration and
development activities such as geological and other administrative costs
associated with overseeing the exploration and development activities. All
internal costs not directly associated with exploration and development
activities were charged to expense as they were incurred. Costs associated with
unevaluated properties are excluded from the full cost pool until we have made a
determination as to the existence
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of proved reserves. The inclusion of our unevaluated costs into the amortization base is expected to be completed within three to five years. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Under this method of accounting, we are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.
Asset retirement obligations
We measure the future cost to retire our tangible long-lived assets and recognize such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties. Our asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. We estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.
Derivatives
From time to time, we have used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil and natural gas. We recognize all of our derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type of hedging relationship. None of our derivatives were designated as hedging instruments during the years endedDecember 31, 2019 and 2018. For derivative instruments not designated as hedging instruments, changes in the fair value of these instruments are recognized in earnings during the period of change.
Accounting for Equity-Based Compensation
We grant various types of equity-based awards including stock options and restricted stock units. These plans and related accounting policies are defined and described more fully in Note 12-Equity-Based Compensation of the Notes to the Consolidated Financial Statements included elsewhere in the Form 10-K. Stock compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period.
Income Taxes
We use the asset and liability method of accounting for income taxes, under
which deferred tax assets and liabilities are recognized for the future tax
consequences of (1) temporary differences between the financial statement
carrying amounts and the tax bases of existing assets and liabilities and (2)
operating loss and tax credit carryforwards. Deferred income tax assets and
liabilities are based on enacted tax rates applicable to the future period when
those temporary differences are expected to be recovered or settled. The effect
of a change in tax rates on deferred tax assets and liabilities is recognized in
income in the period the rate change is enacted. A valuation allowance is
provided for deferred tax assets when it is more likely than not the deferred
tax assets will not be realized.
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Recent Accounting Pronouncements
For information regarding recent accounting pronouncements, See Note 2-Summary of Significant Accounting Policies included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K. Inflation
Inflation inthe United States has been relatively low in recent years and did not have a material impact on results of operations for the years endedDecember 31, 2019 and 2018. Although the impact of inflation has been insignificant in recent years, it is still a factor inthe United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.
Off-balance Sheet Arrangements
We had no off-balance sheet arrangements as ofDecember 31, 2019 . Please read Note 18-Commitments and Contingencies included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K, for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.
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