Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 2021 and 2020. For the discussion of changes from 2019 to 2020 and other financial information related to 2019, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our 2020 Annual Report on Form 10-K, which was filed with the SEC on February 23, 2021.
Overview
We are one of the largest owners and managers of oil and natural gas mineral interests in the 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 of December 31, 2021, our mineral and royalty interests were located in 41 states in the continental United 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
TLW Divestiture
In the third quarter of 2021, we closed on the divestiture of our wholly owned subsidiary, TLW Investments, L.L.C.
("TLW"), effective September 1, 2021 for total proceeds of $0.2 million. TLW holds non-operating working interests and
overriding royalty interests primarily located in Oklahoma and Texas.
Acquisitions
In the second quarter of 2021, we closed an acquisition of mineral and royalty acreage in the northern Midland Basin for
total consideration of $20.8 million. The purchase price consisted of $10.0 million in cash and $10.8 million in common units
of the Partnership. The cash consideration was funded with borrowings under the Credit Facility and funds from operating
activities. The assets acquired consisted of $4.9 million of proved oil and natural gas properties, $15.6 million of unproved oil
and natural gas properties, and $0.3 million of net working capital.
Shelby Trough Update
In Angelina County, Texas, two wells are currently producing under our development agreement with Aethon, and another eight wells are being drilled or completed. Aethon is currently drilling three wells under the separate development agreement covering San Augustine County, Texas.
Austin Chalk Update
We entered into agreements with multiple operators to drill wells using advanced fracturing and completion techniques in the areas of the Austin Chalk in East Texas where we have significant acreage positions. Five wells have been drilled and turned to sales, and another two wells are in various stages of drilling or completion under these agreements. Early results from
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these wells, while showing some variability, demonstrate that higher-intensity completions can significantly improve well performance relative to prior generation completion technology and the performance of unstimulated wells.
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. With widespread availability of vaccines, the U.S. Centers for Disease Control and Prevention has revised its guidance, travel restrictions have started to lift, and businesses have reopened. In the wake of a rise in COVID-19 cases resulting from new variants, we have maintained remote work arrangements for all employees. Employees are allowed the flexibility of going to the office when following health and safety guidelines established by the company. We do not expect these arrangements to negatively impact our ability to maintain operations. We continue to prioritize the health and safety of our workforce through frequent cleaning of common spaces, appropriate physical distancing measures, and other best practices as recommended by federal, 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. During the year ended December 31, 2021, the WTI oil spot prices ranged from a high of $85.64 per Bbl on October 26, 2021 to a low of $47.47 per Bbl on January 4, 2021. During the year ended December 31, 2021, Henry Hub spot natural gas prices ranged from a high of $23.86 per MMBtu on February 17, 2021 to a low of $2.43 per MMBtu on April 5, 2021.
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. Commodity prices improved in late 2020 and fully recovered in 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 the Organization of the Petroleum Exporting Countries and its broader partners. The improvement in commodity prices caused many of our operators to resume their drilling and completion activity on our acreage. 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.
The price environment in 2020, 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 takes into consideration the estimated loan value of our oil and natural gas properties. Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million. The April and October 2021 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million. The next borrowing base redetermination is scheduled for April 2022. In a prolonged period of low commodity prices, we may be required to impair additional properties and the borrowing base under our Credit Facility could be further reduced.
The following table reflects commodity prices at the end of each quarter presented:
2021
Benchmark Prices Fourth Quarter Third Quarter Second Quarter First Quarter
WTI spot crude oil ($/Bbl) 1
$ 75.33 $ 75.22 $ 73.52 $ 59.19
Henry Hub spot natural gas ($/MMBtu) 1
$ 3.82 $ 5.58 $ 3.79 $ 2.52
1 Source: EIA
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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:
2021
U.S. Rotary Rig Count 1
Fourth Quarter Third Quarter Second Quarter First Quarter
Oil 480 421 372 324
Natural gas 106 99 98 92
Other — 1 — 1
Total 586 521 470 417
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 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 2022, at 1.8 Tcf, or 8% higher than the five-year average. The EIA expects inventories will rise to 3.7 Tcf at the end of October 2022, which would be within 1% of the five-year average.
The following table shows natural gas storage volumes by region at the end of each quarter presented:
2021
Region 1
Fourth Quarter Third Quarter Second Quarter First Quarter
(Bcf)
East 767 779 513 307
Midwest 893 934 623 401
Mountain 172 201 173 112
Pacific 219 243 244 194
South Central 1,143 1,013 1,005 749
Total 3,194 3,170 2,558 1,763
1 Source: EIA
Natural Gas Exports
Rising levels of U.S. natural gas exports have been a growing source of demand, particularly in the Gulf Coast region where the majority of our natural gas is produced. The EIA expects natural gas exports will reach record highs in 2022 and continue to grow in 2023 due to a combination of both rising LNG exports and increases in pipeline exports to Mexico. Net natural gas exports averaged 10.7 Bcf per day in 2021 and the EIA forecasts that they will increase to 13.4 Bcf per day in 2022 and 14.3 Bcf per day in 2023.
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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 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 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 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. The rise in LNG exports from the United States has increased demand for domestic natural gas production and had a positive impact on natural gas prices. The EIA expects high levels of U.S. LNG exports to continue into 2022, averaging 16% above 2021 levels. The EIA forecast reflects the assumption that global natural gas demand remains strong and that expected additional U.S. LNG export capacity comes online.
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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. 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 December 31, 2021 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, but not required, 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 December 31, 2021, we had hedged 63% of our available oil and condensate hedge volumes for 2022 and 65% and 14% of our available natural gas hedge volumes for 2022 and 2023, respectively.
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. 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, 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 the U.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.
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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,
2021 2020
(in thousands)
Net income (loss) $ 181,987 $ 121,819
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization 61,019 82,018
Impairment of oil and natural gas properties — 51,031
Interest expense 5,638 10,408
Income tax expense (benefit) (135) 8
Accretion of asset retirement obligations 1,073 1,131
Equity-based compensation 12,218 3,727
Unrealized (gain) loss on commodity derivative instruments 33,528 35,238
(Gain) loss on sale of assets, net (2,850) (24,045)
Adjusted EBITDA 292,478 281,335
Adjustments to reconcile to Distributable cash flow:
Change in deferred revenue (18) (391)
Cash interest expense (4,059) (9,364)
Preferred unit distributions (21,000) (21,000)
Restructuring charges — 4,815
Distributable cash flow $ 267,401 $ 255,395
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Results of Operations
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
The following table shows our production, revenue, and operating expenses for the periods presented:
Year Ended December 31,
2021 2020 Variance
(dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)
3,646 3,895 (249) (6.4) %
Natural gas (MMcf) 1
61,445 67,945 (6,500) (9.6) %
Equivalents (MBoe) 13,887 15,219 (1,332) (8.8) %
Equivalents/day (MBoe) 38.0 41.6 (3.6) (8.7) %
Realized prices, without derivatives:
Oil and condensate ($/Bbl) $ 64.67 $ 38.16 $ 26.51 69.5 %
Natural gas ($/Mcf) 1
4.16 2.04 2.12 103.9 %
Equivalents ($/Boe) $ 35.39 $ 18.89 $ 16.50 87.3 %
Revenue:
Oil and condensate sales $ 235,771 $ 148,631 $ 87,140 58.6 %
Natural gas and natural gas liquids sales 1
255,671 138,926 116,745 84.0 %
Lease bonus and other income 14,292 9,083 5,209 57.3 %
Revenue from contracts with customers 505,734 296,640 209,094 70.5 %
Gain (loss) on commodity derivative instruments (146,474) 46,111 (192,585) NM 2
Total revenue $ 359,260 $ 342,751 $ 16,509 4.8 %
Operating expenses:
Lease operating expense $ 13,056 $ 14,022 $ (966) (6.9) %
Production costs and ad valorem taxes 49,809 43,473 6,336 14.6 %
Exploration expense 1,082 29 1,053 3631.0 %
Depreciation, depletion, and amortization 61,019 82,018 (20,999) (25.6) %
Impairment of oil and natural gas properties — 51,031 (51,031) (100.0) %
General and administrative 48,746 42,983 5,763 13.4 %
Other expense:
Interest expense 5,638 10,408 (4,770) (45.8) %
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, 2021 increased compared to the year ended December 31, 2020. The increase in total revenue from the corresponding period is primarily due to an increase in oil and condensate sales, natural gas and NGL sales, and lease bonus and other income. The overall increase was partially offset by a loss on commodity derivative instruments in 2021 compared to a gain in 2020.
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Oil and condensate sales. Oil and condensate sales for the year ended December 31, 2021 were higher than the corresponding period in 2020 due to higher realized commodity prices partially offset by lower production volumes. The decrease in oil and condensate production was primarily due to reduced production volumes from the Permian Basin and Eagle Ford. The decrease in Permian Basin production was driven by divestitures of certain Permian Basin mineral and royalty properties in the third quarter of 2020 and the decrease in Eagle Ford production was driven by normal production declines with less new development activity. Our mineral and royalty interest oil and condensate volumes accounted for 93% and 92% of total oil and condensate volumes for the years ended December 31, 2021 and 2020, respectively.
Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the year ended December 31, 2021 as compared to the year ended December 31, 2020 due to higher realized commodity prices 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 84% and 76% of our natural gas volumes for the years ended December 31, 2021 and 2020, respectively.
Gain (loss) on commodity derivative instruments. During 2021, we recognized a loss from our commodity derivative instruments compared to a gain 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. During 2021, we recognized $112.9 million of realized losses and $33.5 million of unrealized losses from our commodity derivatives, compared to $81.3 million of realized gains and $35.2 million of unrealized losses in 2020. The unrealized losses on our commodity contracts in 2021 and 2020 were both primarily driven by changes in the forward commodity price curves for oil and 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 higher for the year ended December 31, 2021, as compared to the same period in 2020. Leasing activity in the Austin Chalk and Wolfcamp plays and proceeds from surface use waiver on our mineral acreage supporting solar development in Mississippi, Texas, and California made up the majority of lease bonus and other income in 2021. 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.
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 2021 as compared to 2020, primarily due to 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, 2021, production and ad valorem taxes increased as compared to the year ended December 31, 2020, as a result of higher commodity prices partially offset by lower ad valorem tax estimates.
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 2021 primarily related to a dry hole drilled in the first quarter of 2021. Exploration expense for 2020 was minimal.
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 significant change in reserves or costs. Depreciation, depletion, and amortization expense decreased for the year ended December 31, 2021 as compared to 2020, primarily due to lower production volumes and a reduction in cost basis with lower
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corresponding reduction in proved developed producing reserve quantities. The reduction in cost basis is primarily due to oil and natural gas property divestitures in the third quarter of 2020, and continued depreciation, depletion, and amortization.
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. There was no impairment for December 31, 2021. There was $51.0 million in impairment for 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.
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, 2021, general and administrative expenses increased compared to 2020, primarily due to a $3.5 million increase in cash compensation and a $8.2 million increase in equity-based compensation. The increase in cash compensation was driven by projected outperformance relative to performance targets under our short-term cash incentive plan. The increase in equity-based compensation was due to higher costs recognized for performance-based incentive awards resulting from upward movements in our common unit price during 2021 compared to downward movements in our common unit price in 2020. The overall increase was partially offset by charges recognized in 2020 that did not recur. This included $4.8 million of restructuring costs associated with workforce reductions in the first quarter of 2020 and a $1.1 million increase in allowance against an outstanding long-term receivable.
Other Expense
Interest expense. For the year ended December 31, 2021, interest expense decreased compared to 2020, primarily due to lower average outstanding borrowings partially offset by higher 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, 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
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
The following table shows our cash flows for the periods presented:
Year Ended December 31,
2021 2020 Change
(in thousands)
Cash flows provided by operating activities $ 256,880 $ 281,809 $ (24,929)
Cash flows provided by (used in) investing activities (14,317) 151,246 (165,563)
Cash flows provided by (used in) financing activities (235,483) (439,378) 203,895
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 2021 decreased as compared to 2020. The decrease was primarily due to net cash paid on settlements of commodity derivative instruments in 2021 compared to net cash received in the same period of 2020. The overall decrease was partially offset by increases in oil and condensate sales and natural gas and NGL sales due to higher realized commodity prices.
Investing Activities . Net cash was used in investing activities for 2021 as compared to net cash being provided by investing activities for 2020. The change was primarily due to cash paid for acquisitions of oil and natural gas properties in 2021 compared to proceeds from the sale of oil and natural gas properties in 2020.
Financing Activities . Cash flows used in financing activities for 2021 decreased as compared to 2020. The decrease was primarily due to lower net repayments under our Credit Facility in 2021 compared with 2020. The overall decrease was partially offset by higher distributions paid to common unitholders.
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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 2022 capital expenditure budget associated with our non-operated working interests is expected to be approximately $4.5 million, net of farmout reimbursements. The majority of this capital is anticipated to be spent for workovers and recompletions on existing wells in which we own a working interest.
We spent approximately $4.2 million and $0.6 million associated with our non-operated working interests, net of farmout reimbursements during 2021 and 2020, respectively.
Acquisitions
During 2021 we closed an acquisition of mineral and royalty acreage in the northern Midland Basin for total consideration of $20.8 million. The purchase price consisted of $10.0 million in cash and $10.8 million in common units. The assets acquired consisted of $4.9 million of proved oil and natural gas properties, $15.6 million of unproved oil and natural gas properties, and $0.3 million of net working capital.
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.
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, 2024. As of December 31, 2021, we had outstanding borrowings of $89.0 million at a weighted-average interest rate of 2.61%.
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 November 3, 2020, the borrowing base redetermination reduced the borrowing base to $400.0 million. The April and October 2021 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million. The next semi-annual redetermination is scheduled for April 2022.
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 December 31, 2020 the applicable margin for the alternative base rate ranged from 1.00% and 2.00% and the applicable margin for LIBOR ranged from 2.00% and 3.00% depending on the borrowings outstanding in relation to the borrowing base. As of December 31, 2021, the alternative base rate margin ranged from 1.50% to 2.50% and the LIBOR margin ranged from 2.50% to 3.50%.
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.
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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), if the availability under the Credit Facility is less than 10% of the lenders' commitments, or if total debt to EBITDAX is greater 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 December 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
The following table summarizes our minimum payments as of December 31, 2021 (in thousands):
Payments due by period
Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years
Credit facility $ 89,000 $ — $ 89,000 $ — $ —
Operating lease obligations 2,887 1,428 1,459 — —
Purchase commitments 577 505 72 — —
Total $ 92,464 $ 1,933 $ 90,531 $ — $ —
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 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.
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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, 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 geographic location, 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 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 $60.4 million, $81.3 million, and $109.0 million for the years ended December 31, 2021, 2020, and 2019, 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
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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. The Partnership 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. There was no impairment of proved oil and natural gas properties for the years ended December 31, 2021 and 2019. We recognized $51.0 million of impairment of proved oil and natural gas properties for the year ended December 31, 2020.
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, 2021, 2020, and 2019.
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, 2021 reserve report. Applying this discount results in an approximate 2% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2021 reserve report prepared by NSAI.
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.
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.
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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.
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, 2021 and 2020, 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 our 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 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.
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