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 unaudited consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year endedDecember 31, 2020 ("2020 Annual Report on Form 10-K"). 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 II, Item 1A. Risk Factors." Cautionary Note Regarding Forward-Looking Statements Certain statements and information in this Quarterly Report on Form 10-Q may constitute "forward-looking statements." The words "believe," "expect," "anticipate," "plan," "intend," "foresee," "should," "would," "could," or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below: •our ability to execute our business strategies; •the scope and duration of the COVID-19 pandemic and actions taken by governmental authorities and other parties in response to the pandemic;
•the volatility of realized oil and natural gas prices;
•the level of production on our properties;
•the overall supply and demand for oil and natural gas, regional supply and demand factors, delays, or interruptions of production;
•our ability to replace our oil and natural gas reserves;
•our ability to identify, complete, and integrate acquisitions;
•general economic, business, or industry conditions, including slowdowns, domestically and internationally and volatility in the securities, capital or credit markets;
•competition in the oil and natural gas industry;
•the level of drilling activity by our operators particularly in areas such as the Shelby Trough where we have concentrated acreage positions;
•the ability of our operators to obtain capital or financing needed for development and exploration operations;
•title defects in the properties in which we invest;
•the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;
•restrictions on the use of water for hydraulic fracturing;
•the availability of pipeline capacity and transportation facilities;
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--------------------------------------------------------------------------------•the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
•federal and state legislative and regulatory initiatives relating to hydraulic fracturing;
•future operating results;
•future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;
•exploration and development drilling prospects, inventories, projects, and programs;
•operating hazards faced by our operators;
•the ability of our operators to keep pace with technological advancements; and
•certain factors discussed elsewhere in this filing. For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see "Risk Factors" in our 2020 Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise. 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 production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders. As ofMarch 31, 2021 , 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 Shelby Trough UpdateAngelina County Aethon has successfully drilled the initial two wells under the development agreement coveringAngelina County and expects to turn those wells to sales in the second quarter of 2021. Under the terms of that agreement, Aethon will drill a minimum of four wells on our acreage in the first program year ending inSeptember 2021 , escalating to a minimum of 15 wells per program year starting with the third program year.San Augustine County InMarch 2021 , we reached an agreement withXTO Energy, Inc. ("XTO") to partition jointly owned working interests in the Brent Miller development area inSan Augustine County . Under the partition agreement, we exchanged working interests with XTO in certain existing and proposed drilling units, resulting in each company holding 100% of the working interests in their respective partitioned units. 18 -------------------------------------------------------------------------------- InMay 2021 , we entered into an agreement with Aethon to develop certain of our undeveloped acreage inSan Augustine County , including the working interests resulting from the partition agreement discussed above. 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 five wells to be drilled in the initial program year, which begins in the third quarter of 2021, increasing to a minimum of 12 wells per year beginning with the fourth program year. Our development agreement with Aethon and related drilling commitments covering itsSan Augustine County acreage is independent of the development agreement and associated commitments coveringAngelina County . Austin Chalk Update InApril 2021 , we entered into an agreement 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 in existingAustin Chalk fields. Under the terms of the agreement, the operators will participate in three test wells targeting the Austin Chalk formation. Assuming the test well program is successful, we anticipate entering into separate agreements with each operator to further develop the acreage. InApril 2021 , we also entered into an agreement with a large, private independent operator ("Operator") to drill and complete multipleAustin Chalk wells on our acreage withinEast Texas in 2021. If the initial wells are successful, the Operator has the option to expand the Austin Chalk development program on additional acreage owned by us. Acquisition Update InMay 2021 , we entered into an agreement to acquire mineral and royalty acreage in the northernMidland Basin for total consideration of$20.7 million . The purchase price will consist of$10.0 million in cash and$10.7 million in our common units. The acquisition is expected to close in the second quarter of 2021. 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 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. Commodity Prices and Demand Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. 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 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, resulted in periods of significantly lower market prices for oil, natural gas, and natural gas liquids ("NGLs"). The price environment in 2020 caused many of our operators to reduce their drilling and completion activity on our acreage, which negatively impacts our production volumes. Commodity prices have recovered in late 2020 and into 2021, reflecting expectations of rising demand as both COVID-19 vaccination rates and global economic activity increased, combined with ongoing crude oil production limits from members of theOrganization of the Petroleum Exporting Countries and its broader partners. However, the current price environment remains uncertain as responses to the COVID-19 pandemic continue to evolve. 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. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. 19 -------------------------------------------------------------------------------- The current price environment, including the sharp decline in oil prices that began inMarch 2020 , also caused us to determine that certain depletable units consisting of mature oil producing properties were impaired as ofMarch 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 takes into consideration the estimated loan value of our oil and natural gas properties. EffectiveNovember 3, 2020 , the borrowing base redetermination reduced the borrowing base from$430.0 million to$400.0 million , and effectiveApril 30, 2021 , the borrowing base was reaffirmed at$400.0 million . The next borrowing base redetermination is expected in the fall of 2021. In a prolonged period of low commodity prices, we may be required to impair additional properties and the borrowing base under our Credit Facility could be further reduced. In light of the challenging business environment and uncertainty caused by the pandemic, the board of directors of our general partner (the "Board") also approved a reduction in the quarterly distribution for the first quarter of 2020 to increase the amount of retained free cash flow for debt reduction and balance sheet protection. The Board approved an increase in the quarterly distribution for the second and fourth quarters of 2020, but the distribution remains below 2019 levels. The following table reflects commodity prices as of the last day of each quarter presented: 2021 2020 Benchmark Prices1 First Quarter First Quarter WTI spot oil price ($/Bbl)$ 59.19 $ 20.51 Henry Hub spot natural gas ($/MMBtu) 2.52 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 as of the last day of each quarter presented: 2021 2020 U.S. Rotary Rig Count1 First Quarter First Quarter Oil 324 624 Natural gas 92 102 Other 1 2 Total 417 728
1 Source:
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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 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 estimates that natural gas inventories
concluded the withdrawal season in March 2021 at almost 1.8 Tcf, or 2% lower
than the previous five-year average.
The following table shows natural gas storage volumes by region as of the last
day of each quarter presented:
2021 2020
Region1 First Quarter First Quarter
East 307 382
Midwest 401 476
Mountain 112 92
Pacific 194 197
South Central 749 840
Total 1,763 1,987
1 Source: EIA
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 of Oil 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 New York Mercantile Exchange ("NYMEX") prices are referred to as
differentials. All our production is derived from properties located in the
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 West Texas
Intermediate ("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.
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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 American Petroleum Institute ("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 in the 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.
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. 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. 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 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 of March 31, 2021 are detailed in Note 4 - Commodity Derivative
Financial Instruments to our unaudited consolidated financial statements
included elsewhere in this Quarterly 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 of March 31,
2021 , we have hedged 100% of our available oil and condensate hedge volumes and
81% of our available natural gas hedge volumes for 2021. As of March 31, 2021 ,
we have also hedged 22% of our available oil and condensate hedge volumes for
2022.
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
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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, cash interest expense, distributions to 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 the United States 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.
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:
Three Months Ended March 31,
2021 2020
(in thousands)
Net income (loss) $ 16,186 $ 76,112
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization 15,632 23,182
Impairment of oil and natural gas properties - 51,031
Interest expense 1,210 4,427
Income tax expense (benefit) (157) 36
Accretion of asset retirement obligations 292 272
Equity-based compensation 3,462 (2,894)
Unrealized (gain) loss on commodity derivative instruments 23,359 (81,057)
Adjusted EBITDA 59,984 71,109
Adjustments to reconcile to Distributable cash flow:
Change in deferred revenue (9) (302)
Cash interest expense (953) (4,168)
Preferred unit distributions (5,250) (5,250)
Restructuring charges1 - 4,815
Distributable cash flow $ 53,772 $ 66,204 1 Restructuring charges include non-recurring costs associated with broad workforce reductions in the first quarter of 2020.
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Results of Operations
Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020
The following table shows our production, revenues, pricing, and expenses for
the periods presented:
Three Months Ended March 31,
2021 2020 Variance
(Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls)
829 1,163 (334) (28.7) %
Natural gas (MMcf)1 14,911 18,612 (3,701) (19.9) %
Equivalents (MBoe) 3,314 4,265 (951) (22.3) %
Equivalents/day (MBoe) 36.8 46.9 (10.1) (21.5) %
Realized prices, without derivatives:
Oil and condensate ($/Bbl) $ 53.29 $ 44.79 $ 8.50 19.0 %
Natural gas ($/Mcf)1 2.88 1.97 0.91 46.2 %
Equivalents ($/Boe) $ 26.27 $ 20.81 $ 5.46 26.2 %
Revenue:
Oil and condensate sales $ 44,176 $ 52,093 $ (7,917) (15.2) %
Natural gas and natural gas liquids sales1 42,889 36,642 6,247 17.0 %
Lease bonus and other income 2,385 4,308 (1,923) (44.6) %
Revenue from contracts with customers 89,450 93,043 (3,593) (3.9) %
Gain (loss) on commodity derivative instruments (27,882) 90,011 (117,893) NM2
Total revenue $ 61,568 $ 183,054 $ (121,486) (66.4) %
Operating expenses:
Lease operating expense $ 2,664 $ 3,827 $ (1,163) (30.4) %
Production costs and ad valorem taxes 11,842 12,376 (534) (4.3) %
Exploration expense 1,073 1 1,072 100.0 %
Depreciation, depletion, and amortization 15,632 23,182 (7,550) (32.6) %
Impairment of oil and natural gas properties - 51,031 (51,031) NM2
General and administrative 12,852 11,856 996 8.4 %
Other expense:
Interest expense 1,210 4,427 (3,217) (72.7) %
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 quarter ended March 31, 2021 decreased compared to the
quarter ended March 31, 2020 . The decrease in total revenue from the
corresponding period is due to a loss on our commodity derivative instruments in
the first quarter of 2021 compared to a gain in the first quarter of 2020, a
decrease in oil and condensate sales, and a decrease in lease bonus and other
income. The overall decrease in total revenue was partially offset by an
increase in natural gas and NGL sales.
Oil and condensate sales. Oil and condensate sales decreased for the quarter
ended March 31, 2021 as compared to the corresponding period in 2020 due to
lower production volumes partially offset by higher realized commodity prices.
The decrease in oil and condensate production was primarily driven by production
volume decreases in the Permian Basin . Our
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mineral and royalty interest oil and condensate volumes accounted for 92% of
total oil and condensate volumes for both quarters ended March 31, 2021 and
2020.
Natural gas and natural gas liquids sales. Natural gas and NGL sales increased
for the quarter ended March 31, 2021 as compared to the corresponding prior
period due to higher realized commodity prices partially offset by lower
production volumes. The decrease in natural gas and NGL production was driven by
decreases in working interest production volumes, primarily within the
Haynesville/Bossier play. Mineral and royalty interest production accounted for
82% and 73% of our natural gas volumes for the quarters ended March 31, 2021 and
2020, respectively.
Gain (loss) on commodity derivative instruments. During the first quarter of
2021, we recognized a loss from our commodity derivative instruments compared to
a gain in the same period in 2020. 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. For the
three months ended March 31, 2021 , we recognized $4.5 million of realized losses
and $23.4 million of unrealized losses from our oil and natural gas commodity
contracts, compared to $9.0 million of realized gains and $81.1 million of
unrealized gains in the same period in 2020. The unrealized losses on our
commodity contracts during the first quarter of 2021 and the unrealized gains
for the same period in 2020 were primarily driven by changes in the forward
commodity price curves for oil.
Lease bonus and other income. When we lease our mineral interests, we generally
receive an upfront cash payment, or a lease bonus. Lease bonus revenue 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
for the first quarter of 2021 was lower than the same period in 2020. Leasing
activity in the Austin Chalk play made up the majority of lease bonus revenue in
the first quarter of 2021, while a substantial portion of first quarter 2020
activity came from the Permian Basin , Green River Basin , and Bakken/Three Forks.
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 for the
quarter ended March 31, 2021 as compared to the same period in 2020, 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-operating 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 quarter ended March 31, 2021 ,
production costs and ad valorem taxes decreased as compared to the quarter ended
March 31, 2020 , primarily due to lower ad valorem tax estimates for the 2021 tax
year partially offset by higher production costs attributable to our natural gas
and NGL revenues due to higher commodity prices.
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 the three months ended March 31, 2021
primarily related to a dry hole drilled during the period. Exploration expense
was minimal in the corresponding prior period in 2020.
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 a 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 mid-year
and year-end reserve reports, except when circumstances indicate that there has
been a significant change in reserves or costs. Depreciation, depletion, and
amortization decreased for the quarter ended March 31, 2021 as compared to the
same period in 2020, primarily due to lower production volumes and a reduction
in cost basis with a lower corresponding reduction in proved developed producing
reserve quantities. The reduction in cost basis is primarily due to
depreciation, depletion, and amortization recorded during the prior twelve
months.
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General and administrative. General and administrative expenses are costs not
directly associated with the production of oil and natural gas and include
expenses such as the cost of employee salaries and related benefits, office
expenses, and fees for professional services. For the quarter ended March 31,
2021 , general and administrative expenses increased as compared to the same
period in 2020, primarily due to a $6.4 million increase in equity-based
compensation that was partially offset by a $4.8 million decrease related to
restructuring charges recognized in the first quarter of 2020 and a $1.0 million
decrease in cash compensation. The lower equity-based compensation expense in
2020 relative to the current period was primarily due to downward cost revisions
recognized in 2020 for performance-based incentive awards due to changes in our
common unit price period over period.
Interest expense. Interest expense was lower in the first quarter of 2021
relative to the corresponding period in 2020, due to lower interest rates and
lower average outstanding borrowings under our Credit Facility.
Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash generated from operations, borrowings
under our Credit Facility, proceeds from the issuance of equity and debt, and
proceeds from asset sales. 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. As of March 31,
2021 , we had outstanding borrowings of $111.0 million under the Credit Facility.
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. In light of the
challenging business environment and uncertainty caused by the pandemic, the
Board 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 an increase in the quarterly
distribution for the second and fourth quarters of 2020, but the distribution
remains below 2019 levels. If our borrowings exceed our borrowing base, our
ability to pay cash distributions to our unitholders will be limited.
We intend to finance our future acquisitions with cash generated from
operations, borrowings from our Credit Facility, proceeds from any future
issuances of equity and debt, and proceeds from asset sales. 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.
Cash Flows
The following table shows our cash flows for the periods presented:
Three Months Ended
2021 2020 Change
(in thousands)
Cash flows provided by operating activities $ 55,686 $ 71,450 $ (15,764)
Cash flows provided by (used in) investing activities (214) 1,391 (1,605)
Cash flows used in financing activities (53,479) (77,920) 24,441
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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 flows provided by operating activities
decreased for the three months ended March 31, 2021 as compared to the same
period of 2020. The decrease was primarily due to net cash paid on settlements
of commodity derivative instruments in the three months ended March 31, 2021
compared to net cash received in the same period of 2020.
Investing Activities. Net cash was used in investing activities in the three
months ended March 31, 2021 as compared to net cash provided by investing
activities in the same period of 2020. The change was primarily due to proceeds
from the sale of oil and natural gas properties and farmout reimbursements
received in the first quarter of 2020 with no similar activities in the first
quarter of 2021. These changes were partially offset by a decrease in additions
to oil and natural gas properties.
Financing Activities. Cash flows used in financing activities decreased for the
three months ended March 31, 2021 as compared to the same period of 2020. The
decrease was primarily due to lower distributions to common unitholders in the
three months ended March 31, 2021 as compared to the corresponding prior period.
Development Capital Expenditures
Our 2021 capital expenditure budget associated with our non-operated working
interests is expected to be approximately $5.0 million , net of farmout
reimbursements, of which $0.2 million has been invested in the three months
ended March 31, 2021 . 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.
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 March 31,
2021 , we had outstanding borrowings of $111.0 million at a weighted-average
interest rate of 2.37%.
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
direction of two-thirds of the lenders) each have discretion to request a
borrowing base redetermination one time between scheduled redeterminations. We
also have the right to request a redetermination following acquisition of oil
and natural gas properties in excess of 10% of the value of the borrowing base
immediately prior to such acquisition. The borrowing base is also adjusted if we
terminate our hedge positions or sell oil and natural gas property interests
that have a combined value exceeding 5% of the current borrowing base. In these
circumstances, the borrowing base will be adjusted by the value attributed to
the terminated hedge positions or the oil and natural gas property interests
sold in the most recent borrowing base. Effective November 3, 2020 , the
borrowing base redetermination reduced the borrowing base from $430.0 million to
$400.0 million , and effective April 30, 2021 , the borrowing base was reaffirmed
at $400.0 million and the term of the Credit Facility was extended through
November 1, 2024 . Please see Item 5 of Part II of this quarterly report for a
more detailed description of the amendment to the Credit Facility effective
April 30, 2021 . The next semi-annual redetermination is scheduled for October
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. As
of March 31, 2021 and December 31, 2020 , the applicable margin for the
alternative base rate ranged from 1.00% to 2.00% and the applicable margin for
LIBOR ranged from 2.00% to 3.00%, depending on the borrowings outstanding in
relation to the borrowing base. Effective April 30, 2021 , the LIBOR margin was
increased to between 2.50% and 3.50% and the alternative base rate margin was
increased to between 1.50% and 2.50%.
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
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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), if the availability under the Credit Facility is less than
10% of the lenders' commitments, or if total debt to EBITDAX is less than 3.0.
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
March 31, 2021 , we were in compliance with all debt covenants.
On March 5, 2021 , the U.K. Financial Conduct Authority announced that it intends
to stop persuading or compelling banks to submit LIBOR rates after December 31,
2021 for the 1-week and 2-month U.S. dollar settings and after June 30, 2023 for
the remaining U.S. dollar settings. Our Credit Facility includes provisions to
determine a replacement rate for LIBOR if necessary during its term, based on
the secured overnight financing rate published by the Federal Reserve Bank of
New York ("SOFR"). We currently do not expect the transition from LIBOR to have
a material impact on us.
Contractual Obligations
As of March 31, 2021 , there have been no material changes to our contractual
obligations previously disclosed in our 2020 Annual Report on Form 10-K.
Off-Balance Sheet Arrangements
As of March 31, 2021 , we did not have any material off-balance sheet
arrangements.
Critical Accounting Policies and Related Estimates
As of March 31, 2021 , there have been no significant changes to our critical
accounting policies and related estimates previously disclosed in our 2020
Annual Report on Form 10-K.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
Our major market risk exposure is the pricing of oil, natural gas, and NGLs
produced by our operators. Realized prices are primarily driven by the
prevailing global prices for oil and prices for natural gas and NGLs in the
United States . Prices for oil, natural gas, and NGLs have been historically
volatile, and we expect this unpredictability to continue in the future. The
prices that our operators receive for production depend on many factors outside
of our or their control. To reduce the impact of fluctuations in oil and natural
gas prices on our revenues, we use commodity derivative instruments to reduce
our exposure to price volatility of oil and natural gas. The counterparties to
the contracts are unrelated third parties. The contracts settle monthly in cash
based on a designated floating price. The designated floating price is based on
the NYMEX benchmark for oil and natural gas. We have not designated any of our
contracts as fair value or cash flow hedges. Accordingly, the changes in fair
value of the contracts are included in net income in the period of the change.
See Note 4 - Commodity Derivative Financial Instruments and Note 5 - Fair Value
Measurements to the unaudited interim consolidated financial statements included
elsewhere in this Quarterly Report on Form 10-Q for additional information.
To estimate the effect lower prices would have on our reserves, we reduced the
SEC commodity pricing for the twelve months ended March 31, 2021 by 10%. This
results in an approximate 4% reduction of proved reserve volumes as compared to
the unadjusted March 31, 2021 SEC pricing scenario.
Counterparty and Customer Credit Risk
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Our derivative contracts expose us to credit risk in the event of nonperformance
by counterparties. While we do not require our counterparties to our derivative
contracts to post collateral, we do evaluate the credit standing of such
counterparties as we deem appropriate. This evaluation includes reviewing a
counterparty's credit rating and latest financial information. As of March 31,
2021 , we had seven counterparties, all of which were rated Baa1 or better by
Moody's and are lenders under our Credit Facility.
Our principal exposure to credit risk results from receivables generated by the
production activities of our operators. The inability or failure of our
significant operators to meet their obligations to us or their insolvency or
liquidation may adversely affect our financial results. However, we believe the
credit risk associated with our operators and customers is acceptable.
Interest Rate Risk
We have exposure to changes in interest rates on our indebtedness. As of
March 31, 2021 , we had $111.0 million of outstanding borrowings under our Credit
Facility, bearing interest at a weighted-average interest rate of 2.37%. The
impact of a 1% increase in the interest rate on this amount of debt would have
resulted in an increase in interest expense, and a corresponding decrease in our
results of operations, of $0.3 million for the three months ended March 31,
2021 , assuming that our indebtedness remained constant throughout the period. We
may use certain derivative instruments to hedge our exposure to variable
interest rates in the future, but we do not currently have any interest rate
hedges in place.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the
"Exchange Act"), we have evaluated, under the supervision and with the
participation of management of our general partner, including our general
partner's principal executive officer and principal financial officer, the
effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act)
as of the end of the period covered by this Quarterly Report on Form 10-Q. Our
disclosure controls and procedures are designed to provide reasonable assurance
that the information required to be disclosed by us in reports that we file or
submit under the Exchange Act is accumulated and communicated to management,
including our general partner's principal executive officer and principal
financial officer, as appropriate, to allow timely decisions regarding required
disclosure and is recorded, processed, summarized and reported within the time
periods specified in the rules and forms of the SEC . Based upon that evaluation,
our general partner's principal executive officer and principal financial
officer concluded that our disclosure controls and procedures were effective as
of March 31, 2021 to provide reasonable assurance.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during
the quarter ended March 31, 2021 that materially affected, or are reasonably
likely to materially affect, our internal control over financial reporting.
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