BLACK STONE MINERALS, L.P. The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto presented elsewhere in this Annual Report. This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under "Cautionary Note Regarding Forward-Looking Statements" and "Part I, Item 1A. Risk Factors." This discussion includes a comparison of our results of operations and liquidity and capital resources for 2020 and 2019. For the discussion of changes from 2018 to 2019 and other financial information related to 2018, refer to "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our 2019 Annual Report on Form 10-K, which was filed with theSEC onFebruary 25, 2020 . Overview We are one of the largest owners and managers of oil and natural gas mineral interests inthe United States . Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through marketing our mineral assets for lease, creatively structuring the terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working interest basis. We believe our large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable to growing production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders. As ofDecember 31, 2020 , our mineral and royalty interests were located in 41 states in the continentalUnited States including all of the major onshore producing basins. These non-cost-bearing interests include ownership in over 70,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements. Recent Developments Asset Sales InJuly 2020 , we closed two separate divestitures of certain mineral and royalty properties in thePermian Basin for total proceeds, after final closing adjustments, of$150.6 million . The proceeds were used to reduce outstanding borrowings under our Credit Facility. One of these transactions, effectiveMay 1, 2020 , involved the sale of our mineral and royalty interests in specific tracts inMidland County, Texas for net proceeds of approximately$54.5 million . The other transaction, effectiveJuly 1, 2020 , involved the sale of an undivided interest across parts of ourDelaware Basin andMidland Basin positions for net proceeds of approximately$96.1 million . We estimate the production associated with the properties sold, in total, to be approximately 1,800 Boe per day at the time of the sale.
COVID-19 Pandemic and Commodity Prices
The COVID-19 pandemic has adversely affected the global economy, disrupted
global supply chains and created significant volatility in the financial
markets. In addition, the pandemic has resulted in travel restrictions, business
closures and the institution of quarantining and other restrictions on movement
in many communities. To protect the health and well-being of our workforce in
the wake of COVID-19, we have implemented remote work arrangements for all
employees. We do not expect these arrangements to impact our ability to maintain
operations. We will continue to prioritize the health and safety of our
workforce when employees return to the office through frequent cleaning of
common spaces, appropriate social distancing measures, and other best practices
as recommended by state and local officials.
The impact of the COVID-19 pandemic has negatively affected the oil and natural
gas business environment, primarily by causing a reduction in commercial
activity and travel worldwide thereby lowering energy demand. This, in turn, has
resulted in significantly lower market prices for oil, natural gas, and natural
gas liquids ("NGLs"). While we use derivative instruments to partially mitigate
the impact of commodity price volatility, our revenues and operating results
depend significantly upon the
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prevailing prices for oil and natural gas. The current price environment has
caused many of our operators to reduce their drilling and completion activity on
our acreage, and caused some of our operators to temporarily shut-in production
from existing wells, both of which negatively impact our production volumes.
While we believe most of the shut-in production has been brought back on-line,
drilling and completion activity remains depressed relative to pre-pandemic
levels.
The current price environment, including the sharp decline in oil prices that
began in March 2020 , also caused us to determine that certain depletable units
consisting of mature oil producing properties were impaired as of March 31,
2020 . Therefore, we recognized impairment of oil and natural gas properties of
$51.0 million in the first quarter of 2020. Additionally, the borrowing base
under the Credit Facility, which takes into consideration the estimated loan
value of our oil and natural gas properties, was reduced from $650.0 million to
$460.0 million , effective May 1, 2020 . Effective July 21, 2020 , in connection
with the closing of our two asset sales in the Permian Basin , the borrowing base
was further reduced to $430.0 million . Effective November 3, 2020 , the most
recent borrowing base redetermination reduced the borrowing base to $400.0
million . In a prolonged period of low commodity prices, we may be required to
impair additional properties and the borrowing base under our Credit Facility
could be further reduced. In light of the challenging business environment and
uncertainty caused by the pandemic, the board of directors of our general
partner (the "Board") also approved a reduction in the quarterly distribution
for the first quarter of 2020 to increase the amount of retained free cash flow
for debt reduction and balance sheet protection. The Board approved increases to
the quarterly distribution for the second and fourth quarters of 2020, but the
distribution remains below 2019 levels.
Shelby Trough Update
OnMay 4, 2020 , we entered into a development agreement with affiliates of Aethon Energy ("Aethon") with respect to our undeveloped Shelby Trough Haynesville and Bossier shale acreage inAngelina County, Texas . The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to our mineral and leasehold acreage in the contract area. The agreement calls for a minimum of four wells to be drilled in the initial program year, which began in the third quarter of 2020, increasing to a minimum of 15 wells per year beginning with the third program year. Aethon has successfully spud the initial two program wells under the development agreement. OnJune 10, 2020 , we entered into a new incentive agreement withXTO Energy Inc. ("XTO") with respect to certain drilled but uncompleted wells ("DUCs") in our Shelby Trough acreage inSan Augustine County, Texas . The agreement allows for royalty relief on 13 existing DUCs if XTO completes and turns the wells to sales byMarch 31, 2021 , and complements the recent development agreement with Aethon covering our Shelby Trough acreage inAngelina County towards our goal of reviving volume growth from the area. As ofJanuary 18, 2021 , XTO has turned all 13 DUCs to sales. Austin Chalk Update We are currently working with several operators to test and develop areas of the Austin Chalk inEast Texas where we have significant acreage positions. Recent drilling results have shown that advances in fracturing and other completion techniques can dramatically improve well performance from the Austin Chalk formation. In February of 2021, we entered into an agreement with a large, publicly traded independent operator by which the operator will undertake a program to drill, test, and complete wells in the Austin Chalk formation on certain of our acreage inEast Texas . If successful, the operator has the option to expand its drilling program over a significant acreage position owned and controlled by us.
We are also working with existing operators across our East Texas
Business Environment The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us. COVID-19 Pandemic and Market Conditions
The COVID-19 pandemic and related economic repercussions have resulted in a significant reduction in demand for and prices of oil, natural gas and NGLs. In the first quarter of 2020 and into the second quarter of 2020, oil prices fell sharply, due in part to significantly decreased demand as a result of the COVID-19 pandemic and the announcement bySaudi Arabia of a significant increase in its maximum oil production capacity as well as the announcement byRussia that previously agreed upon oil production cuts between members of theOrganization of the Petroleum Exporting Countries and its broader partners ("OPEC+") would expire onApril 1, 2020 , and the ensuing expiration thereof. Agreed-upon production cuts by OPEC+ along 52 -------------------------------------------------------------------------------- with decliningU.S. production have helped to correct the supply and demand imbalance; however, these reductions are not expected to be enough in the near-term to offset the significant inventory build caused by demand destruction from the COVID-19 pandemic. These market conditions have resulted in a decline in drilling activity as operators revise their capital budgets downward and adjust their operations in response to lower commodity prices. Crude oil and natural gas spot prices in early 2021 and contract future prices for the full year 2021 have improved significantly from levels seen in the second quarter of 2020; however, drilling activity remains depressed relative to levels experienced in 2018 and 2019. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist. Commodity Prices and Demand Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. The EIA forecasts that WTI oil prices will average approximately$49.70 per Bbl in 2021 and$49.81 per Bbl in 2022. During the year endedDecember 31, 2020 , the WTI oil spot price reached a high of$63.27 per Bbl onJanuary 6, 2020 , but decreased to a low of$8.91 per Bbl onApril 21, 2020 . This excludes the period inApril 2020 when WTI briefly traded in negative territory. The EIA forecasts that the Henry Hub spot natural gas price will average$3.01 per MMBtu for 2021 and$3.27 per MMBtu for 2022. During the year endedDecember 31, 2020 ,Henry Hub spot natural gas prices ranged from a high of$3.14 per MMBtu onOctober 26, 2020 to a low of$1.33 per MMBtu onSeptember 21, 2020 . To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts. The following table reflects commodity prices at the end of each quarter presented: 2020 Benchmark Prices Fourth Quarter Third Quarter Second Quarter First Quarter WTI spot crude oil ($/Bbl)1$ 48.35 $
40.05
$ 2.36 $ 1.66 $ 1.76 $ 1.71
1 Source: EIA
Rig Count
As we are not the operator of record on any producing properties, drilling on
our acreage is dependent upon the exploration and production companies that
lease our acreage. In addition to drilling plans that we seek from our
operators, we also monitor rig counts in an effort to identify existing and
future leasing and drilling activity on our acreage.
The following table shows the rig count at the end of each quarter presented:
2020
U.S. Rotary Rig Count1 Fourth Quarter Third Quarter Second Quarter First Quarter
Oil 267 183 188 624
Natural gas 83 75 75 102
Other 1 3 2 2
Total 351 261 265 728
1 Source: Baker Hughes Incorporated
Natural Gas Storage
A substantial portion of our revenue is derived from sales of oil production
attributable to our interests; however, the majority of our production is
natural gas. Natural gas prices are significantly influenced by storage levels
throughout the year. Accordingly, we monitor the natural gas storage reports
regularly in the evaluation of our business and its outlook.
Historically, natural gas supply and demand fluctuates on a seasonal basis. From
April to October, when the weather is warmer and natural gas demand is lower,
natural gas storage levels generally increase. From November to March, storage
levels typically decline as utility companies draw natural gas from storage to
meet increased heating demand due to colder weather. In
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order to maintain sufficient storage levels for increased seasonal demand, a
portion of natural gas production during the summer months must be used for
storage injection. The portion of production used for storage varies from year
to year depending on the demand from the previous winter and the demand for
electricity used for cooling during the summer months. The EIA forecasts that
inventories will conclude the withdrawal season, which is the end of March 2021 ,
at almost 1.6 Tcf, or 12% lower than the five-year average. The EIA expects
inventories will reach almost 3.6 Tcf at the end of October 2021 , which would be
5% lower than the five-year average.
The following table shows natural gas storage volumes by region at the end of
each quarter presented:
2020
Region1 Fourth Quarter Third Quarter Second Quarter First Quarter
(Bcf)
East 771 890 655 385
Midwest 930 1,053 747 472
Mountain 197 235 177 92
Pacific 283 318 308 200
South Central 1,166 1,313 1,221 857
Total 3,347 3,809 3,108 2,006
1 Source: EIA
54-------------------------------------------------------------------------------- How We Evaluate Our Operations We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following: •volumes of oil and natural gas produced; •commodity prices including the effect of derivative instruments; and •Adjusted EBITDA and Distributable cash flow. Volumes of Oil and Natural Gas Produced In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that constitute our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances. Commodity Prices Factors Affecting the Sales Price ofOil and Natural Gas The prices we receive for oil, natural gas, and NGLs vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All our production is derived from properties located inthe United States . •Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials. The chemical composition of oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur. Location differentials generally result from transportation costs based on the produced oil's proximity to consuming and refining markets and major trading points. •Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas inthe United States . The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications. Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets. 55
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Hedging
We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Our open derivative contracts consist of fixed-price swap contracts and costless collar contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. Our costless collar contracts contain a fixed floor price and a fixed ceiling price. If the market price exceeds the fixed ceiling price, we pay the difference between the fixed ceiling price and the market settlement price. If the market price is below the fixed floor price, we receive the difference between the market settlement price and the fixed floor price. If the market price is between the fixed floor and fixed ceiling price, no payments are due from either party. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments. We may employ contractual arrangements other than fixed-price swap contracts and costless collar contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as ofDecember 31, 2020 are detailed in Note 5 - Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual Report. Pursuant to the terms of our Credit Facility, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months. We are allowed to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As ofDecember 31, 2020 , we had hedged 98% of our available oil and condensate hedge volumes and 80% of our available natural gas hedge volumes for 2021. We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above related to such production for the following 12 to 30 months. We do not enter into derivative instruments for speculative purposes. Non-GAAP Financial Measures Adjusted EBITDA and Distributable cash flow are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis. We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets. We define Distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, estimated replacement capital expenditures during the subordination period, cash interest expense, distributions to noncontrolling interests and preferred unitholders, and restructuring charges. Adjusted EBITDA and Distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles ("GAAP") in theU.S. as measures of our financial performance. Adjusted EBITDA and Distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA and Distributable cash flow may differ from computations of similarly titled measures of other companies. 56 -------------------------------------------------------------------------------- The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated: Year Ended December 31, 2020 2019 (in thousands) Net income (loss)$ 121,819 $ 214,368 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 82,018 109,584 Impairment of oil and natural gas properties 51,031 - Interest expense 10,408 21,435 Income tax expense (benefit) 8 (335) Accretion of asset retirement obligations 1,131 1,117 Equity-based compensation 3,727 20,484 Unrealized (gain) loss on commodity derivative instruments 35,238 32,817 (Gain) loss on sale of assets, net (24,045) - Adjusted EBITDA 281,335 399,470
Adjustments to reconcile to Distributable cash flow: Change in deferred revenue
(391) 42
Cash interest expense (9,364) (20,394)
Estimated replacement capital expenditures1 - (2,750)
Preferred unit distributions (21,000) (21,000)
Restructuring charges 4,815 -
Distributable cash flow $ 255,395 $ 355,368
1 The Board established a replacement capital expenditure estimate of $11.0
million for the period of April 1, 2018 to March 31, 2019 . Due to the expiration
of the subordination period, we do not intend to establish a replacement capital
expenditure estimate for periods subsequent to March 31, 2019 .
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Results of Operations
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
The following table shows our production, revenue, and operating expenses for
the periods presented:
Year Ended December 31,
2020 2019 Variance
(dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls) 3,895 4,777 (882) (18.5) %
Natural gas (MMcf)1 67,945 77,635 (9,690) (12.5) %
Equivalents (MBoe) 15,219 17,716 (2,497) (14.1) %
Equivalents/day (MBoe) 41.6 48.5 (6.9) (14.2) %
Realized prices, without derivatives:
Oil and condensate ($/Bbl) $ 38.16 $ 55.20 $ (17.04) (30.9) %
Natural gas ($/Mcf)1 2.04 2.57 (0.53) (20.6) %
Equivalents ($/Boe) $ 18.89 $ 26.13 $ (7.24) (27.7) %
Revenue:
Oil and condensate sales $ 148,631 $ 263,678 $ (115,047) (43.6) %
Natural gas and natural gas liquids sales1 138,926 199,265 (60,339) (30.3) %
Lease bonus and other income 9,083 29,833 (20,750) (69.6) %
Revenue from contracts with customers 296,640 492,776 (196,136) (39.8) %
Gain (loss) on commodity derivative instruments 46,111 (4,955) 51,066 NM2
Total revenue $ 342,751 $ 487,821 $ (145,070) (29.7) %
Operating expenses:
Lease operating expense $ 14,022 $ 17,665 $ (3,643) (20.6) %
Production costs and ad valorem taxes 43,473 60,533 (17,060) (28.2) %
Exploration expense 29 397 (368) (92.7) %
Depreciation, depletion, and amortization 82,018 109,584 (27,566) (25.2) %
Impairment of oil and natural gas properties 51,031 - 51,031 NM2
General and administrative 42,983 63,353 (20,370) (32.2) %
Other expense:
Interest expense 10,408 21,435 (11,027) (51.4) %
1 As a mineral and royalty interest owner, we are often provided insufficient
and inconsistent data on NGL volumes by our operators. As a result, we are
unable to reliably determine the total volumes of NGLs associated with the
production of natural gas on our acreage. Accordingly, no NGL volumes are
included in our reported production; however, revenue attributable to NGLs is
included in our natural gas revenue and our calculation of realized prices for
natural gas.
2 Not meaningful.
Revenue
Total revenue for the year ended December 31, 2020 decreased compared to the
year ended December 31, 2019 . The decrease in total revenue from the
corresponding period is primarily due to a decrease in oil and condensate sales
and natural gas and NGL sales as a result of lower realized commodity prices and
lower production volumes, and a decrease in lease bonus and other income. The
overall decrease was partially offset by a gain on commodity derivative
instruments in 2020 compared to a loss in 2019.
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Oil and condensate sales. Oil and condensate sales for the year ended
December 31, 2020 were lower than the corresponding period in 2019 due to
decreased production volumes and lower realized commodity prices. The decrease
in oil and condensate production was primarily driven by lower production in the
Permian Basin and the Bakken/Three Forks. Our mineral and royalty interest oil
and condensate volumes accounted for 92% of total oil and condensate volumes for
each of the years ended December 31, 2020 and 2019.
Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased
for the year ended December 31, 2020 as compared to the year ended December 31,
2019 due to lower realized commodity prices and lower production volumes. The
decrease in natural gas production was driven by lower volumes in the
Haynesville/Bossier play primarily due to reduced drilling activity and shut-in
production volumes associated with the completion of certain DUCs on our Shelby
Trough acreage. Mineral and royalty interest production accounted for 76% and
69% of our natural gas volumes for the years ended December 31, 2020 and 2019,
respectively.
Gain (loss) on commodity derivative instruments. During 2020, we recognized a
gain from our commodity derivative instruments compared to a loss in 2019. Cash
settlements we receive represent realized gains, while cash settlements we pay
represent realized losses related to our commodity derivative instruments. In
addition to cash settlements, we also recognize fair value changes on our
commodity derivative instruments in each reporting period. The changes in fair
value result from new positions and settlements that may occur during each
reporting period, as well as the relationships between contract prices and the
associated forward curves. During 2020, we recognized $81.3 million of realized
gains and $35.2 million of unrealized losses from our commodity derivatives,
compared to $27.9 million of realized gains and $32.8 million of unrealized
losses in 2019. The unrealized losses on our commodity contracts in 2020 were
primarily driven by changes in the forward commodity price curves for oil and
natural gas. The unrealized losses on our commodity contracts in 2019 were
primarily driven by changes in the forward commodity price curves for oil,
partially offset by changes in the forward commodity price curves for natural
gas.
Lease bonus and other income. When we lease our mineral interests, we generally
receive an upfront cash payment, or a lease bonus. Lease bonus income can vary
substantively between periods because it is derived from individual transactions
with operators, some of which may be significant. Lease bonus and other income
was lower for the year ended December 31, 2020 , as compared to the same period
in 2019. Leasing activity in the Permian Basin , Haynesville/Bossier, Green River
Basin , and Bakken/Three Forks plays as well as certain surface leases in Polk
County, Texas made up the majority of lease bonus and other income in 2020.
Leasing activity in the Bakken/Three Forks, Haynesville/Bossier, Permian Basin ,
and Woodbine plays, as well as proceeds from the settlement of a dispute with
one of our operators, made up the majority of lease bonus and other income in
2019.
Operating Expenses
Lease operating expense. Lease operating expense includes recurring expenses
associated with our non-operated working interests necessary to produce
hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring
expenses, such as well repairs. Lease operating expense decreased in 2020 as
compared to 2019, primarily due to lower nonrecurring service-related expenses,
including workovers, as well as a decrease in variable costs as a result of
lower production from our non-operated working interest properties.
Production costs and ad valorem taxes. Production taxes include statutory
amounts deducted from our production revenues by various state taxing entities.
Depending on the regulations of the states where the production originates,
these taxes may be based on a percentage of the realized value or a fixed amount
per production unit. This category also includes the costs to process and
transport our production to applicable sales points. Ad valorem taxes are
jurisdictional taxes levied on the value of oil and natural gas minerals and
reserves. Rates, methods of calculating property values, and timing of payments
vary between taxing authorities. For the year ended December 31, 2020 ,
production and ad valorem taxes decreased as compared to the year ended
December 31, 2019 , as a result of lower commodity prices and lower production
volumes.
Exploration expense. Exploration expense typically consists of dry-hole
expenses, delay rentals, and geological and geophysical costs, including seismic
costs, and is expensed as incurred under the successful efforts method of
accounting. Exploration expense for 2020 was minimal. Exploration expense for
2019 primarily consisted of costs incurred to acquire 3-D seismic information
related to our mineral and royalty interests from a third-party service
provider.
Depreciation, depletion, and amortization. Depletion is the amount of cost basis
of oil and natural gas properties attributable to the volume of hydrocarbons
extracted during such period, calculated on a units-of-production basis.
Estimates of proved developed producing reserves are a major component of the
calculation of depletion. We adjust our depletion rates semi-annually based upon
the mid-year and year-end reserve reports, except when circumstances indicate
that there has been a
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significant change in reserves or costs. Depreciation, depletion, and
amortization expense decreased for the year ended December 31, 2020 as compared
to 2019, primarily due to lower production volumes and a reduction in cost basis
with lower corresponding reduction in proved developed producing reserve
quantities. The reduction in cost basis is primarily due to oil and natural gas
property divestitures, continued depreciation, depletion, and amortization, and
oil and natural gas property impairments.
Impairment of oil and natural gas properties. Individual categories of oil and
natural gas properties are assessed periodically to determine if the net book
value for these properties has been impaired. Management periodically conducts
an in-depth evaluation of the cost of property acquisitions, successful
exploratory wells, development activities, unproved leasehold, and mineral
interests to identify impairments. Impairments totaled $51.0 million for the
year ended December 31, 2020 , primarily due to declines in future expected
realizable net cash flows as a result of lower commodity prices as of the
measurement date of March 31, 2020 . There were no impairments for 2019.
General and administrative. General and administrative expenses are costs not
directly associated with the production of oil and natural gas and include the
cost of employee salaries and related benefits, office expenses, and fees for
professional services. For the year ended December 31, 2020 , general and
administrative expenses decreased compared to 2019, primarily due to a $8.9
million decrease in cash compensation and a $16.8 decrease in equity-based
compensation. The decrease in cash compensation is primarily resulting from the
broad workforce reductions in the first quarter of 2020. The decrease in
equity-based compensation is due in part to these same workforce reductions but
also due to downward cost revisions recognized in 2020 for performance-based
incentive awards due to the decrease in our common unit price period over
period. The overall decrease was partially offset by $4.8 million of
restructuring charges in the first quarter of 2020 associated with the workforce
reductions.
Other Expense
Interest expense. For the year ended December 31, 2020 , interest expense
decreased compared to 2019, primarily due to lower average outstanding
borrowings and lower interest rates under our Credit Facility.
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Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash generated from operations, borrowings
under our Credit Facility, and proceeds from the issuance of equity and debt.
Our primary uses of cash are for distributions to our unitholders, reducing
outstanding borrowings under our Credit Facility, and for investing in our
business, specifically the acquisition of mineral and royalty interests and our
selective participation on a non-operated working interest basis in the
development of our oil and natural gas properties.
The Board has adopted a policy pursuant to which, at a minimum, distributions
will be paid on each common unit for each quarter to the extent we have
sufficient cash generated from our operations after establishment of cash
reserves, if any, and after we have made the required distributions to the
holders of our outstanding preferred units. However, we do not have a legal or
contractual obligation to pay distributions on our common units quarterly or on
any other basis, and there is no guarantee that we will pay distributions to our
common unitholders in any quarter. The Board may change the foregoing
distribution policy at any time and from time to time.
We intend to finance our future acquisitions with cash generated from
operations, borrowings from our Credit Facility, and proceeds from any future
issuances of equity and debt. Over the long-term, we intend to finance our
working interest capital needs with our executed farmout agreements and
internally-generated cash flows, although at times we may fund a portion of
these expenditures through other financing sources such as borrowings under our
Credit Facility. Replacement capital expenditures are expenditures necessary to
replace our existing oil and natural gas reserves or otherwise maintain our
asset base over the long-term. The Board established a replacement capital
expenditure estimate of $11.0 million for the period of April 1, 2018 to March
31, 2019 . Due to the expiration of the subordination period, we do not intend to
establish a replacement capital expenditure estimate for periods subsequent to
March 31, 2019 .
Cash Flows
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
The following table shows our cash flows for the periods presented:
Year Ended December 31,
2020 2019 Change
(in thousands)
Cash flows provided by operating activities $ 281,809 $ 412,720 $ (130,911)
Cash flows provided by (used in) investing activities 151,246 (48,623) 199,869
Cash flows provided by (used in) financing activities (439,378)
(361,392) (77,986)
Operating Activities. Our operating cash flows are dependent, in large part, on
our production, realized commodity prices, derivative settlements, lease bonus
revenue, and operating expenses. Cash provided by operating activities for 2020
decreased as compared to 2019. The decrease was primarily due to decreased oil
and condensate sales and natural gas and NGL sales driven by lower realized
commodity prices and lower production. The overall decrease was partially offset
by higher net cash received on settlement of commodity derivative instruments.
Investing Activities. Net cash was provided by investing activities for 2020 as
compared to net cash used in investing activities for 2019. The change was
primarily due to increased proceeds from the sale of oil and natural gas
properties as well as a decrease in oil and natural gas property acquisitions
and additions in 2020 as compared with 2019.
Financing Activities. Cash flows used in financing activities for 2020 increased
as compared to 2019. The increase was primarily due to increased net repayments
under our Credit Facility in 2020 compared with 2019. The overall increase was
partially offset by lower distributions to common unitholders and decreased
repurchases of common units.
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Development Capital Expenditures
In the first quarter of each calendar year, we establish a capital budget and
then monitor it throughout the year. Our capital budget is created based upon
our estimate of internally-generated cash flows and the ability to borrow and
raise additional capital. Actual capital expenditure levels will vary, in part,
based on actual cash generated, the economics of wells proposed by our operators
for our participation, and the successful closing of acquisitions. The timing,
size, and nature of acquisitions are unpredictable.
Our 2021 capital expenditure budget associated with our non-operated working
interests is expected to be approximately $5 million , net of farmout
reimbursements. The majority of this capital is anticipated to be spent for
working interest participation on test wells in the Austin Chalk play and the
remaining will be spent for workovers on existing wells in which we own a
working interest.
During 2020, we spent approximately $0.6 million associated with our
non-operated working interests, net of farmout reimbursements.
During 2019, we spent approximately $4.3 million associated with our
non-operated working interests, net of farmout reimbursements. The majority of
this capital was spent for workovers on existing wells in which we own a working
interest or for acquiring new leasehold acreage for subsequent farmout in the
Haynesville/Bossier play.
Acquisitions
We had no acquisition activity during 2020,
During 2019 we spent approximately $43.1 million and issued common units valued
at $0.9 million related to acquisitions of mineral and royalty interests, which
also included proved oil and natural gas properties.
During 2018 we spent approximately $127.3 million and issued common units valued
at $22.6 million related to acquisitions of mineral and royalty interests, which
also included proved oil and natural gas properties.
See Note 4 - Oil and Natural Gas Properties to the consolidated financial
statements included elsewhere in this Annual Report for additional information.
Credit Facility
Pursuant to our $1.0 billion senior secured revolving credit agreement, as
amended (the "Credit Facility"), the commitment of the lenders equals the lesser
of the aggregate maximum credit amounts of the lenders and the borrowing base,
which is determined based on the lenders' estimated value of our oil and natural
gas properties. Borrowings under the Credit Facility may be used for the
acquisition of properties, cash distributions, and other general corporate
purposes. Our Credit Facility terminates on November 1, 2022 . As of December 31,
2020 , we had outstanding borrowings of $121.0 million at a weighted-average
interest rate of 2.40%.
The borrowing base is redetermined semi-annually, typically in April and October
of each year, by the administrative agent, taking into consideration the
estimated loan value of our oil and natural gas properties consistent with the
administrative agent's normal lending criteria. The administrative agent's
proposed redetermined borrowing base must be approved by all lenders to increase
our existing borrowing base, and by two-thirds of the lenders to maintain or
decrease our existing borrowing base. In addition, we and the lenders (at the
election of two-thirds of the lenders) each have discretion to have the
borrowing base redetermined once between scheduled redeterminations. We also
have the right to request a redetermination following the acquisition of oil and
natural gas properties in excess of 10% of the value of the borrowing base
immediately prior to such acquisition. Effective October 23, 2019 , the borrowing
base redetermination reduced the borrowing base to $650.0 million . Effective May
1, 2020 , the borrowing base was further reduced to $460.0 million . Effective
July 21, 2020 , in connection with the closing of two asset sales in the Permian
Basin , the borrowing base was further reduced to $430.0 million . Effective
November 3, 2020 , the most recent borrowing base redetermination reduced the
borrowing base to $400.0 million . The next semi-annual redetermination is
scheduled for April 2021 .
Outstanding borrowings under the Credit Facility bear interest at a floating
rate elected by us equal to an alternative base rate (which is equal to the
greatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or
1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin.
Effective October 31, 2018 , the applicable margin for the alternative base rate
was reduced to between 0.75% and 1.75% and the applicable margin for LIBOR was
reduced to between
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1.75% and 2.75%. Effective November 3, 2020 , the LIBOR margin was increased to
between 2.00% and 3.00% and the alternative base rate margin was increased to
between 1.00% and 2.00%.
We are obligated to pay a quarterly commitment fee ranging from a 0.375% to
0.500% annualized rate on the unused portion of the borrowing base, depending on
the amount of the borrowings outstanding in relation to the borrowing base.
Principal may be optionally repaid from time to time without premium or penalty,
other than customary LIBOR breakage, and is required to be paid (a) if the
amount outstanding exceeds the borrowing base, whether due to a borrowing base
redetermination or otherwise, in some cases subject to a cure period, or (b) at
the maturity date. Our Credit Facility is secured by substantially all of our
oil and natural gas production and assets.
Our credit agreement contains various affirmative, negative, and financial
maintenance covenants. These covenants, among other things, limit additional
indebtedness, additional liens, sales of assets, mergers and consolidations,
dividends and distributions, transactions with affiliates, and entering into
certain derivative agreements, as well as require the maintenance of certain
financial ratios. The credit agreement contains two financial covenants: total
debt to EBITDAX of 3.5:1.0 or less and a current ratio of 1.0:1.0 or greater as
defined in the credit agreement. Distributions are not permitted if there is a
default under the credit agreement (including the failure to satisfy one of the
financial covenants) or during any time that our borrowing base is lower than
the loans outstanding under the credit agreement. The lenders have the right to
accelerate all of the indebtedness under the credit agreement upon the
occurrence and during the continuance of any event of default, and the credit
agreement contains customary events of default, including non-payment, breach of
covenants, materially incorrect representations, cross-default, bankruptcy, and
change of control. There are no cure periods for events of default due to
non-payment of principal and breaches of negative and financial covenants, but
non-payment of interest and breaches of certain affirmative covenants are
subject to customary cure periods. As of December 31, 2020 , we were in
compliance with all debt covenants.
On July 27, 2017 , the U.K. Financial Conduct Authority announced that it intends
to stop persuading or compelling banks to submit LIBOR rates after 2021. Our
Credit Facility includes provisions to determine a replacement rate for LIBOR if
necessary during its term, which require that we and our lenders agree upon a
replacement rate based on the then-prevailing market convention for similar
agreements. We currently do not expect the transition from LIBOR to have a
material impact on us. However, if clear market standards and replacement
methodologies have not developed as of the time LIBOR becomes unavailable, we
may have difficulty reaching agreement on acceptable replacement rates under our
Credit Facility. In the event that we do not reach agreement on an acceptable
replacement rate for LIBOR, outstanding borrowings under the Credit Facility
would revert to a floating rate equal to the alternative base rate (which, as of
the time that LIBOR becomes unavailable, is equal to the greater of the Prime
Rate and the Federal Funds effective rate plus 0.50%) plus the applicable margin
for the alternative base rate which ranges between 1.00% and 2.00%. If we are
unable to negotiate replacement rates on favorable terms, it could have a
material adverse effect on our financial condition, results of operations, and
cash distributions to unitholders.
Contractual Obligations
The following table summarizes our minimum payments as of December 31, 2020 (in
thousands):
Payments due by period
Less Than 1 More Than 5
Total Year 1-3 Years 3-5 Years Years
Credit facility $ 121,000 $ - $ 121,000 $ - $ -
Operating lease obligations 4,288 1,401 2,884 3 -
Purchase commitments 998 884 114 - -
Total $ 126,286 $ 2,285 $ 123,998 $ 3 $ -
Off-Balance Sheet Arrangements
At December 31, 2020 , we did not have any material off-balance sheet
arrangements.
Critical Accounting Policies and Related Estimates
The discussion and analysis of our financial condition and results of operations
are based upon the consolidated financial statements, which have been prepared
in accordance with GAAP. Certain of our accounting policies involve judgments
and uncertainties to such an extent that there is a reasonable likelihood that
materially different amounts would have been reported under different
conditions, or if different assumptions had been used. The following discussions
of critical accounting estimates, including any related discussion of
contingencies, address all important accounting areas where the nature of
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accounting estimates or assumptions could be material due to the levels of
subjectivity and judgment necessary to account for highly uncertain matters or
the susceptibility of such matters to change. We have provided expanded
discussion of our more significant accounting estimates below.
Please read the notes to the consolidated financial statements included
elsewhere in this Annual Report for additional information regarding our
accounting policies.
Use of Estimates
The preparation of consolidated financial statements in conformity with GAAP
requires us to make estimates and assumptions that affect the reported amounts
of assets and liabilities and the disclosure of contingent assets and
liabilities at the date of the consolidated financial statements, as well as
reported amounts of revenues and expenses for the periods herein. Actual results
could differ from those estimates.
Our consolidated financial statements are based on a number of significant
estimates including oil and natural gas reserve quantities that are the basis
for the calculations of depreciation, depletion, and amortization ("DD&A") and
impairment of oil and natural gas properties. Reservoir engineering is a
subjective process of estimating underground accumulations of oil and natural
gas. There are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves. The accuracy of any reserve estimates is a
function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, reserve estimates may differ from the
quantities of oil and natural gas that are ultimately recovered. Our reserve
estimates are determined by an independent petroleum engineering firm. Other
items subject to significant estimates and assumptions include the carrying
amount of oil and natural gas properties, valuation of commodity derivative
financial instruments, valuation of future asset retirement obligations ("ARO"),
determination of revenue accruals, and the determination of the fair value of
equity-based awards.
We evaluate estimates and assumptions on an ongoing basis using historical
experience and other factors, including the current economic and commodity price
environment. The volatility of commodity prices results in increased uncertainty
inherent in such estimates and assumptions. A significant decline in oil or
natural gas prices could result in a reduction in our fair value estimates and
cause us to perform analyses to determine if our oil and natural gas properties
are impaired. As future commodity prices cannot be predicted accurately, actual
results could differ significantly from estimates.
Oil and Natural Gas Properties
We follow the successful efforts method of accounting for oil and natural gas
operations. Under this method, costs to acquire mineral and royalty interests
and working interests in oil and natural gas properties, property acquisitions,
successful exploratory wells, development costs, and support equipment and
facilities are capitalized when incurred. Acquisitions of proved oil and natural
gas properties and working interests are generally considered business
combinations and are recorded at their estimated fair value as of the
acquisition date. Acquisitions that consist of all or substantially all unproved
oil and natural gas properties are generally considered asset acquisitions and
are recorded at cost.
The costs of unproved leaseholds and non-producing mineral interests are
capitalized as unproved properties pending the results of exploration and
leasing efforts. As unproved properties are determined to be productive, the
related costs are transferred to proved oil and natural gas properties. The
costs related to exploratory wells are capitalized pending determination of
whether proved commercial reserves exist. If proved commercial reserves are not
discovered, such drilling costs are expensed. In some circumstances, it may be
uncertain whether proved commercial reserves have been discovered when drilling
has been completed. Such exploratory well drilling costs may continue to be
capitalized if the reserve quantity is sufficient to justify completion as a
producing well and sufficient progress in assessing the reserves and the
economic and operating viability of the project is ongoing. Other exploratory
costs, including annual delay rentals and geological and geophysical costs, are
expensed when incurred.
Oil and natural gas properties are grouped in accordance with the Extractive
Industries - Oil and Gas Topic of the Financial Accounting Standards Board
Accounting Standards Codification. The basis for grouping is a reasonable
aggregation of properties with a common geological structural feature or
stratigraphic condition, such as a reservoir or field, which we also refer to as
a depletable unit.
As exploration and development work progresses and the reserves associated with
our oil and natural gas properties become proved, capitalized costs attributed
to the properties are charged as an operating expense through DD&A. DD&A of
producing oil and natural gas properties is recorded based on the
units-of-production method. Capitalized development costs are amortized on the
basis of proved developed reserves while leasehold acquisition costs and the
costs to acquire proved properties
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are amortized on the basis of all proved reserves, both developed and
undeveloped. Proved reserves are estimated quantities of oil and natural gas
which geological and engineering data demonstrate with reasonable certainty to
be commercially recoverable in future years from known reservoirs under existing
economic and operating conditions. DD&A expense related to our producing oil and
natural gas properties was $81.3 million , $109.0 million , and $122.5 million for
the years ended December 31, 2020 , 2019, and 2018, respectively.
We evaluate impairment of producing properties whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. This evaluation is performed on a depletable unit basis. We compare
the undiscounted projected future cash flows expected in connection with a
depletable unit to its unamortized carrying amount to determine recoverability.
When the carrying amount of a depletable unit exceeds its estimated undiscounted
future cash flows, the carrying amount is written down to its fair value, which
is measured as the present value of the projected future cash flows of such
properties. The factors used to determine fair value include estimates of proved
reserves, future commodity prices, timing of future production, operating costs,
future capital expenditures, and a risk-adjusted discount rate.
There was a collapse in oil prices during the first quarter of 2020 due to
geopolitical events that increased supply at the same time demand weakened due
to the impact of the COVID-19 pandemic. We determined these events and
circumstances indicated a possible decline in the recoverability of the carrying
value of certain proved properties and recoverability testing determined that
certain depletable units consisting of mature oil producing properties were
impaired as of March 31,2020 . We recognized $51.0 million of impairment of
proved oil and natural gas properties for the year ended December 31, 2020 .
There was no impairment of proved oil and natural gas properties for the years
ended December 31, 2019 and 2018.
Unproved properties are also assessed for impairment periodically on a
depletable unit basis when facts and circumstances indicate that the carrying
value may not be recoverable, at which point an impairment loss is recognized to
the extent the carrying value exceeds the estimated recoverable value. The
carrying value of unproved properties, including unleased mineral rights, is
determined based on management's assessment of fair value using factors similar
to those previously noted for proved properties, as well as geographic and
geologic data. There was no impairment of unproved properties for the years
ended December 31, 2020 , 2019, and 2018.
Upon the sale of a complete depletable unit, the book value thereof, less
proceeds or salvage value, is charged to income. Upon the sale or retirement of
an individual well, or an aggregation of interests which make up less than a
complete depletable unit, the proceeds are credited to accumulated DD&A, unless
doing so would significantly alter the DD&A rate of the depletable unit, in
which case a gain or loss is recorded.
We are unable to predict future commodity prices with any greater precision than
the futures market. To estimate the effect lower prices would have on our
reserves, we applied a 10% discount to the commodity prices used in our
December 31, 2020 reserve report. Applying this discount results in an
approximate 4% reduction of estimated proved reserve volumes as compared to the
undiscounted pricing scenario used in our December 31, 2020 reserve report
prepared by NSAI.
Asset Retirement Obligations
Under various contracts, permits, and regulations, we have legal obligations to
restore the land at the end of operations at certain properties where we own
non-operated working interests. Estimating the future restoration costs
necessary for this accounting calculation is difficult. Most of these
restoration obligations are many years, or decades, in the future and the
contracts and regulations often have vague descriptions of what practices and
criteria must be met when the event actually occurs. Asset-restoration
technologies and costs, regulatory and other compliance considerations,
expenditure timing, and other inputs into the valuation of the obligation,
including discount and inflation rates, are also subject to change.
Fair values of legal obligations to retire and remove long-lived assets are
recorded when the obligation is incurred and becomes determinable. When the
liability is initially recorded, we capitalize this cost by increasing the
carrying amount of the related property. Over time, the liability is accreted
for the change in its present value, and the capitalized cost in oil and natural
gas properties is depleted based on units-of-production consistent with the
related asset.
Revenues from Contracts with Customers
Accounting Standards Codification ("ASC") 606, Revenue from Contracts with
Customers, requires us to identify the distinct promised goods and services
within a contract which represent separate performance obligations and determine
the transaction price to allocate to the performance obligations identified. We
adopted ASC 606 using the modified retrospective method, which was applied to
all existing contracts for which all (or substantially all) of the revenue had
not been recognized under legacy revenue guidance as of the date of
adoption, January 1, 2018 .
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Oil and natural gas sales
Sales of oil and natural gas are recognized at the point control of the product
is transferred to the customer and collectability of the sales price is
reasonably assured. Oil is priced on the delivery date based upon prevailing
prices published by purchasers with certain adjustments related to oil quality
and physical location. The price we receive for natural gas is tied to a market
index, with certain adjustments based on, among other factors, whether a well
delivers to a gathering or transmission line, quality and heat content of
natural gas, and prevailing supply and demand conditions, so that the price of
natural gas fluctuates to remain competitive with other available natural gas
supplies. As each unit of product represents a separate performance obligation
and the consideration is variable as it relates to oil and natural gas prices,
we recognize revenue from oil and natural gas sales using the practical
expedient for variable consideration in ASC 606.
Lease bonus and other income
We also earn revenue from lease bonuses and delay rentals. We generate lease
bonus revenue by leasing mineral interests to exploration and production
companies. A lease agreement represents our contract with a customer and
generally transfers the rights to any oil or natural gas discovered, grants us a
right to a specified royalty interest, and requires that drilling and completion
operations commence within a specified time period. Control is transferred to
the lessee and we have satisfied our performance obligation when the lease
agreement is executed, such that revenue is recognized when the lease bonus
payment is received. At the time we execute the lease agreement, we expect to
receive the lease bonus payment within a reasonable time, though in no case more
than one year, such that we have not adjusted the expected amount of
consideration for the effects of any significant financing component per the
practical expedient in ASC 606. We also recognize revenue from delay rentals to
the extent drilling has not started within the specified period, payment has
been received, and we have no further obligation to refund the payment.
Allocation of transaction price to remaining performance obligations
Oil and natural gas sales
We have utilized the practical expedient in ASC 606 which states 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. As we have determined that each unit of
product generally represents a separate performance obligation, future volumes
are wholly unsatisfied and disclosure of the transaction price allocated to
remaining performance obligations is not required.
Lease bonus and other income
Given that we do not recognize lease bonus or other income until a lease
agreement has been executed, at which point its performance obligation has been
satisfied, and payment is received, we do not record revenue for unsatisfied or
partially unsatisfied performance obligations as of the end of the reporting
period. Overall, there were no material changes in the timing of the
satisfaction of our performance obligations or the allocation of the transaction
price to our performance obligations in applying the guidance in ASC 606 as
compared to legacy GAAP.
Prior-period performance obligations
We record oil and natural gas revenue in the month production is delivered to
the purchaser. As a non-operator, we have limited visibility into the timing of
when new wells start producing and production statements may not be received for
30 to 90 days or more after the date production is delivered. 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. The expected sales
volumes and prices for these properties are estimated and recorded within the
Accounts receivable line item in the accompanying consolidated balance sheets.
The difference between our estimates and the actual amounts received for oil and
natural gas sales is recorded in the month that payment is received from the
third party. For the years ended December 31, 2020 and 2019, revenue recognized
in the reporting periods related to performance obligations satisfied in prior
reporting periods was immaterial.
Commodity Derivative Financial Instruments
Our ongoing operations expose us to changes in the market price for oil and
natural gas. To mitigate the given price risk associated with its operations, we
use commodity derivative financial instruments. From time to time, such
instruments may include variable-to-fixed price swaps, costless collars,
fixed-price contracts, and other contractual arrangements. We do not
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enter into derivative instruments for speculative purposes. The impact of these derivative instruments could affect the amount of revenue we ultimately record. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheets. Gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments. Although these derivative instruments may expose us to credit risk, we monitor the creditworthiness of our counterparties. Equity-Based Compensation We recognize equity-based compensation expense for unit-based awards granted to our employees and the Board. Total compensation expense for unit-based awards is calculated based on the number of units expected to vest multiplied by the grant-date fair value per unit. Compensation expense for time-based restricted unit awards with graded vesting requirements are recognized using straight-line attribution over the requisite service period. Compensation expense related to the restricted performance unit awards is determined by multiplying the number of common units underlying such awards that, based on our estimate, are probable to vest, by the measurement-date (i.e., the last day of each reporting period date) fair value and recognized using the accelerated or straight-line attribution methods, depending on the terms of the award. Equity-based compensation expense related to unit-based awards is included in General and administrative expense within the consolidated statements of operations. Distribution equivalent rights for the restricted performance unit awards that are expected to vest are charged to partners' capital. Please read Note 9 - Incentive Compensation within the consolidated financial statements included elsewhere in this Annual Report for additional information. New and Revised Financial Accounting Standards The effects of new accounting pronouncements are discussed in Note 2 - Summary of Significant Accounting Policies within the consolidated financial statements included elsewhere in this Annual Report.
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