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, 2022 ("2022 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 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;
•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;
•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;
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•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;
•conservation measures and general concern about the environmental impact of the production and use of fossil fuels;
•cybersecurity incidents, including data security breaches or computer viruses; 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 2022 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, 2023 , 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 68,000 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 Development Update
Aethon has successfully turned sixteen wells to sales and has commenced operations on ten additional wells under the development agreement coveringAngelina County . Aethon has successfully turned 4 wells to sales and has another nine wells awaiting completion operations under the separate development agreement coveringSan Augustine County . Additionally,XTO Energy has resumed drilling on our Shelby Trough acreage inSan Augustine County and has one well currently awaiting completion operations.
Austin Chalk Update
We have entered into agreements with multiple operators to drill wells in the areas of the Austin Chalk inEast Texas , where we have significant acreage positions. The results of our 2021 three well test program in theBrookeland Field demonstrates that modern completion technology can greatly improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation. Eight operators are actively engaged in redevelopment of the field, with two rigs running continuously in the play. To date, twenty-two wells with modern completions are now producing in the area, and an additional six are currently either being drilled or completed. 19 --------------------------------------------------------------------------------
Business Environment
The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.
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. Commodity prices decreased from the prior period endedMarch 31, 2022 , due to several factors, including reduced demand for natural gas and rising global oil inventories. Natural gas prices decreased in the first quarter of 2023 as a result of reduced consumption due to the early emergence of warmer than expected weather conditions in the first two months of the quarter. The current price environment remains uncertain as responses to elevated inflation and the conflict inUkraine continue to evolve. The EIA expects relatively flatU.S. natural gas production, increases in LNG exports, and increased consumption in the electric power sector will raise prices in 2023. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these 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 following table reflects commodity prices at the end of each quarter presented: 2023 2022 Benchmark Prices1 First Quarter First Quarter WTI spot oil price ($/Bbl)$ 75.68 $ 100.53 Henry Hub spot natural gas ($/MMBtu) 2.10 5.46 1 Source: EIA Rig Count
As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.
The following table shows the rig count at the end of each quarter presented:
2023 2022
U.S. Rotary Rig Count1 First Quarter First Quarter
Oil 592 531
Natural gas 160 137
Other 3 2
Total 755 670
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 will conclude the injection season inOctober 2023 at 3.8 Tcf, which is 6% higher than the previous five-year average. The following table shows natural gas storage volumes by region at the end of each quarter presented: 2023 2022 Region1 First Quarter First Quarter East 335 268 Midwest 421 317 Mountain 80 89 Pacific 73 161 South Central 921 581 Total 1,830 1,416 1 Source: EIA Natural Gas Exports The EIA expects an increase inU.S. LNG exports resulting from three major LNG export projects under construction that will come online by the end of 2024. Net natural gas exports averaged 11.6 Bcf per day in the first quarter of 2023, a 10% increase from the 2022 average. The EIA forecasts average exports of 12.2 Bcf per day for the rest of 2023 and 12.7 Bcf per day for 2024. The EIA forecast reflects the assumption that production remains flat and that expected additionalU.S. LNG export capacity comes online. 21 --------------------------------------------------------------------------------
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
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 andNew York Mercantile Exchange ("NYMEX") prices are referred to as differentials. All our production is derived from properties located inthe United States . •Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to asWest 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. 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 itsAmerican 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 inthe United States . The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.
Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.
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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 ofMarch 31, 2023 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, 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 ofMarch 31, 2023 , we had hedged 67% and 22% of our available oil and condensate hedge volumes for 2023 and 2024, respectively. As ofMarch 31, 2023 , we had also hedged 64% and 41% of our available natural gas hedge volumes for 2023 and 2024, 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, if any, 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, if
any. 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, if any.
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.
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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:
Three Months Ended March 31,
2023 2022
(in thousands)
Net income (loss) $ 134,443 $ (7,002)
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization 11,147 10,917
Interest expense 814 1,209
Income tax expense (benefit) 147 103
Accretion of asset retirement obligations 245 202
Equity-based compensation 2,118 4,551
Unrealized (gain) loss on commodity derivative instruments (38,986) 88,776
Adjusted EBITDA 109,928 98,756
Adjustments to reconcile to Distributable cash flow:
Change in deferred revenue (5) (9)
Cash interest expense (559) (862)
Preferred unit distributions (5,250) (5,250)
Distributable cash flow $ 104,114 $ 92,635
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Results of Operations
Three Months Ended
The following table shows our production, revenue, and operating expenses for the periods presented:
Three Months Ended March 31,
2023 2022 Variance
(Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls)
793 831 (38) (4.6) %
Natural gas (MMcf)1 16,452 12,759 3,693 28.9 %
Equivalents (MBoe) 3,535 2,958 577 19.5 %
Equivalents/day (MBoe) 39.3 32.9 6.4 19.5 %
Realized prices, without derivatives:
Oil and condensate ($/Bbl) $ 76.81 $ 91.25 $ (14.44) (15.8) %
Natural gas ($/Mcf)1 3.49 5.94 (2.45) (41.2) %
Equivalents ($/Boe) $ 33.47 $ 51.25 $ (17.78) (34.7) %
Revenue:
Oil and condensate sales $ 60,909 $ 75,831 $ (14,922) (19.7) %
Natural gas and natural gas liquids sales1 57,423 75,754 (18,331) (24.2) %
Lease bonus and other income 3,975 4,859 (884) (18.2) %
Revenue from contracts with customers 122,307 156,444 (34,137) (21.8) %
Gain (loss) on commodity derivative instruments 52,271 (120,020) 172,291 (143.6) %
Total revenue $ 174,578 $ 36,424 $ 138,154 379.3 %
Operating expenses:
Lease operating expense $ 2,668 $ 3,161 $ (493) (15.6) %
Production costs and ad valorem taxes 12,667 13,949 (1,282) (9.2) %
Exploration expense 4 180 (176) (97.8) %
Depreciation, depletion, and amortization 11,147 10,917 230 2.1 %
General and administrative 12,648 13,763 (1,115) (8.1) %
Other expense:
Interest expense 814 1,209 (395) (32.7) %
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.
Revenue
Total revenue for the quarter ended March 31, 2023 increased compared to the
quarter ended March 31, 2022 . The increase in total revenue from the
corresponding period is primarily due to a gain from our commodity derivative
instruments compared to a loss in the prior period and was partially offset by a
decrease in oil and condensate sales, natural gas and NGL sales, and lease bonus
and other income.
Oil and condensate sales. Oil and condensate sales decreased for the quarter
ended March 31, 2023 as compared to the corresponding period in 2022 primarily
due to lower realized commodity prices and production volumes. Our mineral and
royalty interest oil and condensate volumes accounted for 92% and 94% of total
oil and condensate volumes for quarters ended March 31, 2023 and 2022,
respectively.
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Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased
for the quarter ended March 31, 2023 as compared to the corresponding prior
period. The decrease was primarily due to lower realized commodity prices
between the comparative periods partially offset by higher production volumes
due to the timing of new development. The increase in natural gas and NGL
production was primarily driven by new development in the Haynesville/Bossier
play trend. Mineral and royalty interest production accounted for 94% and 89% of
our natural gas volumes for the quarters ended March 31, 2023 and 2022,
respectively.
Gain (loss) on commodity derivative instruments. During the first quarter of
2023, we recognized a gain from our commodity derivative instruments compared to
a loss in the same period in 2022. 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, 2023 , we recognized $13.3 million of realized gains
and $39.0 million of unrealized gains from our oil and natural gas commodity
contracts, compared to $31.2 million of realized losses and $88.8 million of
unrealized losses in the same period in 2022. The unrealized gains on our
commodity contracts during the first quarter of 2023 were primarily driven by
changes in the forward commodity price curves for natural gas. The unrealized
losses for the same period in 2022 were 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 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 2023 was lower than the same period in 2022. Leasing
activity in the Haynesville/Bossier and Wolfcamp plays made up the majority of
lease bonus and other income for the first quarter of 2023, while a substantial
portion of the first quarter 2022 activity came from leasing activity in the
Wolfcamp play.
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, 2023 as compared to the same period in 2022, primarily
due to lower nonrecurring service-related expenses, including workovers.
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, 2023 ,
production costs and ad valorem taxes decreased as compared to the quarter ended
March 31, 2022 , primarily due to lower production taxes stemming from falling
commodity prices partially offset by higher 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 was minimal for the quarter ended March 31, 2023
and in the corresponding prior period in 2022.
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 increased for the quarter ended March 31, 2023 as compared to the
same period in 2022, primarily due to increased production partially offset by 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,
2023 , general and administrative expenses decreased slightly as compared to the
same period in 2022, primarily due to a $2.4 million decrease in equity
compensation offset by a $1.7 million increase in cash compensation. The
decrease in equity incentive compensation was due to lower costs recognized for
performance-based incentive awards due to downward movements in our common unit
price period over period.
Interest expense. Interest expense was lower in the first quarter of 2023
relative to the corresponding period in 2022, due to lower average outstanding
borrowings under our Credit Facility and partially offset by higher interest
rates.
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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. As ofMarch 31, 2023 , no balance was outstanding under the Credit Facility. We have the option to redeem Series B cumulative convertible preferred units beginning onNovember 28, 2023 . See Note 9 to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information. 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 any 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 March 31,
2023 2022 Change
(in thousands)
Cash flows provided by operating activities
(1,954) (96) (1,858)
Cash flows used in financing activities (120,358) (84,703) (35,655)
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 increased for the three months endedMarch 31, 2023 as compared to the same period of 2022. The increase was primarily due to higher cash settlements received on our commodity derivative instruments as compared to cash settlements paid in the same period of 2022. Investing Activities. Net cash used in investing activities in the three months endedMarch 31, 2023 increased as compared to the same period of 2022. The increase was primarily due to increased cash additions to oil and natural gas properties, net of farmout reimbursements in the three months endedMarch 31, 2023 as compared to the corresponding prior period. Financing Activities. Cash flows used in financing activities increased for the three months endedMarch 31, 2023 as compared to the same period of 2022. The increase was primarily due to higher distributions to unitholders in the three months endedMarch 31, 2023 as compared to the corresponding prior period.
Development Capital Expenditures
Our 2023 capital expenditure budget associated with our non-operated working interests is expected to be approximately$7.9 million , net of farmout reimbursements, of which$1.9 million has been invested in the three months endedMarch 31, 2023 . The majority of this capital is anticipated to be spent for workovers and recompletions on existing wells in which we own a working interest. 28 --------------------------------------------------------------------------------
Credit Facility
We maintain a senior secured revolving credit agreement, as amended, (the "Credit Facility"). The Credit Facility has an aggregate maximum credit amount of$1.0 billion . The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. Borrowings under the Credit Facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes. Our Credit Facility terminates onOctober 31, 2027 . As ofMarch 31, 2023 , no balance was outstanding under the Credit Facility. The borrowing base is redetermined semi-annually, usually in April and October and is derived from the value of our oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. 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 the 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. The April andOctober 2021 andApril 2022 borrowing base redeterminations reaffirmed the borrowing base at$400.0 million . InOctober 2022 , we revised and amended the Credit Facility to extend the maturity date fromNovember 1, 2024 toOctober 31, 2027 . Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was increased to$550.0 million and we elected to lower commitments under the Credit Facility from$400.0 million to$375.0 million . TheApril 2023 borrowing base redetermination reaffirmed the borrowing base at$550.0 million with cash commitments at$375.0 million .The next semi-annual redetermination is scheduled forOctober 2023 . InOctober 2022 , the Credit Facility was amended to replace the LIBOR rate with the secured overnight financing rate published by theFederal Reserve Bank of New York ("SOFR"). Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by us equal to a base rate (which is a rate per annum equal to the highest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate in effect on such day plus 0.50%, and (c) Adjusted Term SOFR for a one month tenor in effect on such day plus 1.00%) or Adjusted Term SOFR, in each case, plus the applicable margin. As ofDecember 31, 2022 andMarch 31, 2023 , the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the Adjusted Term SOFR margin ranged from 2.50% to 3.50%, depending on the borrowings outstanding in relation to the borrowing base. 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 SOFR 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 ofMarch 31, 2023 , we were in compliance with all debt covenants.
Contractual Obligations
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