UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON D.C. 20549

FORM 10-K

☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 20212022

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934

COMMISSION FILE NUMBER: 000-55615

ENERGY 11, L.P.

(Exact name of Registrant as specified in its charter)

Registrant’s telephone number, including area code: (817) 882-9192

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Exchange Act:

Common Units of Limited Partnership Interest

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ 

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

There is no established public market for the registrant’s outstanding limited partnership interests. The aggregate market value of the registrant’s limited partnership interests held by non-affiliates of the registrant as of June 30, 20212022 was $0.

As of March 16, 2022,31, 2023, the Partnership had 18,973,474 common units outstanding.

ENERGY 11, L.P.

FORM 10-K

Index

FORWARD LOOKING STATEMENTS

Certain statements within this report may constitute forward-looking statements. Forward-looking statements are those that do not relate solely to historical fact. They include, but are not limited to, any statement that may predict, forecast, indicate or imply future results, performance, achievements or events. You can identify these statements by the use of words such as “may,” “will,” “could,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “predict,” “continue,” “further,” “seek,” “plan” or “project” and variations of these words or comparable words or phrases of similar meaning.

These forward-looking statements include such things as:

These forward-looking statements reflect the Partnership’s current beliefs and expectations with respect to future events and are based on assumptions and are subject to risks and uncertainties and other factors outside the Partnership’s control that may cause actual results to differ materially from those projected. Such factors include, but are not limited to, those described under “Risk Factors” and the following:

Although the Partnership believes the expectations reflected in such forward-looking statements are based upon reasonable assumptions, the Partnership cannot assure investors that its expectations will be attained or that any deviations will not be material. Investors are cautioned that forward-looking statements speak only as of the date they are made and that, except as required by law, the Partnership undertakes no obligation to update these forward-looking statements to reflect any future events or circumstances. All subsequent written or oral forward-looking statements attributable to the Partnership or to individuals acting on its behalf are expressly qualified in their entirety by this section.

Item 1.Business

Overview

Energy 11, L.P. (the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership completed its best-efforts offering on April 24, 2017 with a total of approximately 19 million common units sold for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.

As of December 31, 2021,2022, the Partnership owns an approximate 25%24% non-operated working interest in 266293 producing wells, an estimated approximate 23%12% non-operated working interest in 6 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Chord Energy Corporation (“Chord”, NASDAQ: CHRD), the product of a merger between Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL)and Oasis Petroleum Inc., is one of the largest producers in the basin and operates substantially all of the Sanish Field Assets.

The general partner of the Partnership is Energy 11 GP, LLC (the “General Partner”).

Business Objective

The Partnership’s primary investment objectives are to (i) acquire producing and non-producing oil and natural gas properties with development potential, and to enhance the value of the properties through drilling and other development activities, (ii) make distributions to the holders of the common units, (iii) engage in a liquidity transaction, after five – seven years, in which all properties are sold and the sales proceeds are distributed to the partners, merge with another entity, or list the common units on a national securities exchange, and (iv) permit holders of common units to invest in oil and natural gas properties in a tax efficient basis. The proceeds from the sale of the common units primarily have been used to acquire the Sanish Field Assets and develop these assets.

Investment and Historical Drilling Activity

On December 18, 2015, the Partnership completed its first purchase in the Sanish field, acquiring an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. On January 11, 2017, the Partnership closed on its second purchase, acquiring an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. On March 31, 2017, the Partnership closed on its third purchase, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s then 216 existing producing wells and 150 of the Partnership’s then 253 future development locations in the Sanish Field Assets for approximately $52.4 million.

Since the beginning of 2018, the Partnership has elected to participate in the drilling and completion of 6786 new wells in the Sanish field. Fifty-one (51)field, of which 80 of these 6786 wells have been completed and were producing at December 31, 2021.2022. The Partnership has six wells that are in-process as of December 31, 2021 and expects ten wells2022, which are anticipated to commence drillingbe completed in the first quarterhalf of 2022.2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 6786 wells is approximately $89$119 million, of which approximately $70$116 million had been incurred as of December 31, 2021.2022.

Industry Operating Environment

The outbreak of a novel coronavirus (“COVID-19”) in China in December 2019 significantly impacted the global economy throughout 2020, and the domestic oil and gas industry was especially impacted as demand for oil, natural gas and other hydrocarbons substantially declined, beginning in March and April 2020. In addition to the outbreak of COVID-19, Saudi Arabia and Russia, two of the largest worldwide producers of crude oil, engaged in a price war during March and April 2020 that ultimately led to excess crude oil and natural gas inventory and congested supply chain channels, which weighed negatively on commodity prices while demand was low. As government-mandated COVID-19 restrictions eased during the fourth quarter of 2020 and into 2021, demand for oil and natural gas returned. Production restraint by domestic and foreign operators in 2021, in conjunction with higher worldwide demand, contributed to higher commodity prices throughout 2021, with domestic oil prices averaging approximately $77 per barrel for the fourth quarter and approximately $68 for the full year. Multiple variants of COVID-19 have caused disruption in the global economy since the initial outbreak, and future variants of COVID-19 or other global health concerns may impact the oil and gas industry.

In addition to the specific macroeconomic impact of COVID-19, the oil and natural gas industry is affected by othermany factors that the Partnership generally cannot control, including the prices of oil, natural gas and natural gas liquids (“NGL”). Global macroeconomic factors contributing to uncertainty within the industry include real or perceived geopolitical risks in oil-producing regions of the world, particularly Russia and the Middle East;East and Russia; current and/or future government sanctions impacting certain oil producing nations; forecasted levels of global economic growth combined with forecasted global supply; supply levels of oil and natural gas due to exploration and development activities in the United States; global health concerns, such as the outbreak of COVID-19 in December 2019; environmental and climate change regulation; actions taken by OPEC;the Organization of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. Natural gas prices vary in accordance with North American supply and demand and are also affected by imports and exports of NGL. Weather also has a significant impact on demand for natural gas since it is a primary heating source in the United States.

Commodity prices strengthened throughout 2021, primarily driven by increased demand resulting from the initial recovery from the COVID-19 pandemic and production restraint by domestic and foreign operators. The ongoing military conflict between Russia and Ukraine and related economic sanctions imposed on Russia along with additional production growth by OPEC have further exacerbated supply shortages. In 2022, oil market prices averaged over $90 per barrel, with a peak in second quarter at over $120 per barrel. In addition, natural gas market prices averaged $6.45 per MMBtu in 2022, approximately 68% higher than 2021.

Consistent with non-operators of well interests within the industry, the Partnership engages in oil and natural gas well development by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include the Partnership’s acreage. The Partnership relies on its operators to propose, permit and initiate the drilling of wells. The Partnership assesses each drilling opportunity on a case-by-case basis and participates in wells that expect to meet a desired return based upon estimates of recoverable oil and natural gas, expected oil and gas prices, expertise of the operator and completed well cost from each project, as well as other factors.

The Partnership’s operators generally market and sell the oil and natural gas extracted from Partnership wells. In addition, these operators coordinate the transportation of oil and natural gas production from wells in which the Partnership participates to appropriate pipelines or rail transport facilities pursuant to arrangements that such operators negotiate and maintain with various parties purchasing the production. The price at which Partnership production is sold is generally tied to a market spot price, and the differential between the market spot price and the Partnership’s realized sales price represents the imbedded transportation costs in moving the oil from wellhead to refinery and will fluctuate based on availability of pipeline, rail and other transportation methods.

Production, Prices and Production Cost History

The following table sets forth certain information regarding the production volumes, average prices received, and average production costs associated with the sale of oil, natural gas, and natural gas liquids for the periods indicated below.

Related Parties

The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to any existing related party transactions, as well as any new significant related party transactions.

See further discussion of transactions with related parties in Note 8 titled “Related Parties” in Part II, Item 8 – Financial Statements and Supplementary Data, appearing elsewhere in this Annual Report on Form 10-K.

Partners’ Equity and Distributions

The Partnership completed its best-efforts offering of common units on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership had completed the sale of approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offerings costs of $349.6 million. David Lerner Associates, Inc. was the dealer manager for the Partnership’s best-efforts offering (the “Dealer Manager”). Under the agreement with the Dealer Manager, the Dealer Manager received a total of 6% in selling commissions and marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold in the offering, the total contingent fee is a maximum of approximately $15.0 million, which will only be paid if Payout occurs, as defined below.

Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights (owned by the General Partner), with respect to Class B units or the contingent, incentive payments to the Dealer Manager, until Payout occurs.

The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to market volatility caused by the onset of the COVID-19 pandemic and the impact on the Partnership’s operating cash flows. Further, the Partnership was restricted in making distributions to limited partners under its credit agreements with Simmons Bank (paid off in full in May 2021) and BancFirst (entered in May 2021) until certain conditions within those credit agreements had been met. In November 2021, theThe Partnership successfully met the required conditions under its BancFirst credit agreement to resume distributions to limited partners. Subsequently, the General Partner approved a partial distributionpartners in November 2021 and a full distribution in2021. For the year ended December 2021.31, 2022, the Partnership paid distributions of $1.258082 per common unit, or $23.9 million. For the year ended December 31, 2021, the Partnership declared and paid distributions of $0.189863 per common unit, or $3.6 million. For the year ended December 31, 2020, the Partnership paid distributions of $0.241644 per common unit, or $4.6 million.

The Partnership accumulates unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs, as defined above. As of December 31, 2021,2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.

Oil and Natural Gas Reserves

The table below summarizes the Partnership’s estimated net proved reserves as of December 31, 2021:2022:

The table above represents estimates only. Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. In addition, the Partnership may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond its control. Prices for oil at December 31, 20212022 were abovebelow the 20212022 average prices using the parameters established by the SEC. Due to the volatility of the market, a period of sustained higher or lower prices will have a positive or negative impact to the estimated quantities and present values of the Partnership’s reserves.

Proved Undeveloped Reserves (PUD)

At December 31, 2021,2022, the Partnership had PUDs of approximately 6,62710,522 MBOE, or approximately 29%37% of total proved reserves. Total PUDs at December 31, 20202021 were 4,9596,627 MBOE. The following table reflects the changes in PUDs during 2021: 2022:

Under current SEC requirements, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of their date of original booking unless specific circumstances justify a longer time. The Partnership will be required to remove current PUDs if the Partnership does not drill those reserves within the required five-year time frame, unless specific circumstances justify a longer time. For example, the Partnership removed a portion of its PUDs during the second quarter of 2020 in conjunction with the significant drop in commodity prices caused by COVID-19 as the Partnership did not anticipate all PUD locations would be drilled within the five-year time frame. All of the Partnership’s PUDs at December 31, 20212022 are scheduled to be drilled within five years of the date they were initially recorded. However, since the Partnership is not the operator of any of its oil and natural gas properties, it is difficult to predict with certainty the timing of drilling and completion of wells currently classified as PUD reserves. Historically, energy commodity prices have been volatile, and due to global supply and demand fluctuations, the Partnership continues to expect significant price volatility. Sustained lower prices for oil and natural gas may cause the Partnership in the future to forecast less capital to be available for development of its PUDs, which may cause the Partnership to decrease the number of PUDs it expects to develop within the five-year time frame. In addition, lower oil and natural gas prices may cause the Partnership’s PUDs to become uneconomic to develop, which would cause the Partnership to remove them from the proved undeveloped category.

Internal Controls Over Reserve Estimates and Qualifications of Technical Persons

The Partnership’s policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate its oil and gas reserves quantities and present values in compliance with rules, regulations and guidance provided by the SEC, as well as established industry practices used by independent engineering firms and the Partnership’s peers, and in accordance with the SPE 2007 Standards promulgated by the Society of Petroleum Engineers. The Partnership engaged Pinnacle Energy Services, LLC (“Pinnacle Energy”) to prepare the reserve estimates for all of the Partnership’s assets for the year ended December 31, 20212022 in this annual report. Pinnacle Energy founder J.P. Dick has over 30 years of experience in the oil and natural gas industry, with exposure to reserves and reserve related valuations and issues during that time and is a Registered Professional Engineer in the states of Texas and Oklahoma. Further qualifications include a Bachelor of Science in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, Mr. Dick is an active participant in industry reserve seminars, professional industry groups and is a member of the Society of Petroleum Engineers.

The Partnership’s controls over reserve estimates include engaging Pinnacle Energy as the Partnership’s independent petroleum engineer. The Partnership provided information about its oil and natural gas properties, including production profiles, prices and costs, to Pinnacle Energy and they prepared estimates of the Partnership’s reserves attributable to the Partnership’s properties. All of the information regarding reserves in this annual report on Form 10-K is derived from the report of Pinnacle Energy, which is included as an exhibit to this annual report on Form 10-K.

The Partnership’s management works closely with Pinnacle Energy to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process as well as to review properties and discuss the methods and assumptions used by Pinnacle Energy in their preparation of the year-end reserve estimates. The Partnership’s management also reviews the methods and assumptions used by Pinnacle Energy in the preparation of year-end reserve estimates and assesses them for reasonableness. The Board of Directors of the General Partner also meets with the Partnership’s President and management to discuss matters and policies related to the Partnership’s reserves.

The Partnership’s methodologies include reviews of production trends, analogy to comparable properties, and/or volumetric analysis. Performance methods are preferred. Reserve estimates for proved undeveloped properties are based primarily on volumetric analysis or analogy to offset production in the same or similar fields. The Partnership applies and maintains internal controls, including but not limited to the following, to ensure the reliability of reserves estimations:

Total Productive Wells

The following table sets forth information with respect to the Partnership’s ownership interest in productive wells as of December 31, 2021:2022:

Of the total well count for 2021, none are multiple completions.

Productive wells are producing wells and wells the Partnership deems mechanically capable of production, including shut-in wells, wells waiting for completion, plus wells that are drilled/cased and completed, but waiting for pipeline hook-up. At December 31, 2021,2022, the Partnership had 266293 currently producing wells and onethree shut-in well.wells. A gross well is a well in which the Partnership owns a working interest. The number of net wells represents the sum of fractional working interests the Partnership owns in gross wells.

Developed and Undeveloped Acreage Position

The following table sets forth information with respect to the Partnership’s gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2021,2022, all of which is located in the State of North Dakota in the United States:

As is customary in the oil and natural gas industry, the Partnership can generally retain an interest in undeveloped acreage through drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which the Partnership has an interest are for varying primary terms and, if production under a lease continues from developed lease acreage beyond the primary term, the Partnership is entitled to hold the lease for as long as oil or natural gas is produced. The oil and natural gas properties consist primarily of oil and natural gas wells and interests in developed leasehold acreage.

Undeveloped Acreage Expirations

The Partnership has no undeveloped acreage expirations as all acreage is held by production.

Delivery Commitments

As of December 31, 2021,2022, the Partnership had no commitments to deliver a fixed quantity of oil or natural gas.

Marketing and Customers

The market for the Partnership’s oil and natural gas production depends on factors beyond its control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil and natural gas, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Whiting,Chord, as the primary operator of Partnership’s properties, operates 98%99% of the Partnership’s wells and sold approximately 99% of the Partnership’s production on the Partnership’s behalf in 2021.2022.

Title to Properties

As is customary in the Partnership’s industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, was made at the time the Partnership acquired its properties. The Partnership believes that its title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in the Partnership’s operations. The interests owned by the Partnership may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in the Partnership’s operations.

Insurance

Since the Partnership is not the operator of any of its properties, the Partnership relies on the insurance of the operators of its properties, of which the Partnership’s share of the cost is allocated back to the Partnership through the joint operating agreement. The Partnership’s operators have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to its oil and natural gas properties, control of well, auto liability, marine liability, worker’s compensation and employer’s liability, among other things.

The Partnership re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that the Partnership will be able to maintain insurance in the future at rates that the Partnership considers reasonable and the Partnership may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

Competition

The oil and natural gas industry is highly competitive. The Partnership will encounter strong competition from independent oil and gas companies, master limited partnerships and from major oil and gas companies in contracting for drilling equipment and arranging the services of trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than those of the Partnership.

The Partnership also may be affected by competition for drilling rigs, human resources and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. The Partnership is unable to predict when, or if, such shortages may occur or how they would affect the Partnership’s development and exploitation program.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit the Partnership’s drilling and producing activities and other operations in certain areas where the Partnership may acquire producing properties. These seasonal anomalies can pose challenges for meeting the Partnership’s drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increased costs or delay the Partnership’s operations. Generally, demand for natural gas is higher in summer and winter months. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter natural gas requirements during off–peak months. This can lessen seasonal demand fluctuations.

Environmental, Health and Safety Matters and Regulation

The Partnership’s operations are subject to stringent and complex federal, state and local laws and regulations that govern the oil and natural gas industry, as well as regulations that protect the environment from the discharge of materials into the environment. These laws and regulations may, among other things:

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on the Partnership’s operating costs. In general, the oil and natural gas industry has been the subject of increased legislation and regulatory attention with respect to environmental matters. The trend of more expansive and stricter environmental regulation may continue for the long term.

The following is a summary of some of the existing laws, rules and regulations to which the Partnership’s business operations are subject.

Solid and Hazardous Waste Handling

The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous solid waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, the Partnership expects its operators to generate waste as a routine part of their operations that may be subject to RCRA. Although a substantial amount of the waste expected to be generated is regulated as non–hazardous solid waste rather than hazardous waste, there is no guarantee that the Environmental Protection Agency (“EPA”) or individual states will not adopt more stringent requirements for the handling of non–hazardous or exempt waste or categorize some non–hazardous or exempt waste as hazardous in the future.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, imposes strict, joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so-called potentially responsible parties, or PRPs, include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of the Partnership’s operators’ expected operations, the operators will generate wastes that may fall within CERCLA’s definition of hazardous substance and may dispose of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum, and there is no guarantee that federal law will not adopt more stringent requirements with respect to the petroleum substances. The Partnership may also be the owner of sites on which hazardous substances have been released. If contamination is discovered at a site on which the Partnership is or has been an owner or to which the Partnership sent hazardous substances, the Partnership could be liable for the costs of investigation and remediation and natural resources damages. Further, the Partnership could be required to suspend or cease operations in contaminated areas.

The Partnership may own producing properties that have been used for oil and natural gas exploration and production for many years. Hazardous substances, wastes or hydrocarbons may have been released on or under the Partnership’s properties, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of the properties the Partnership has acquired may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under Partnership control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws.

In general, the list of substances regulated as hazardous under CERCLA has been expanding over time. For example, in September 2022, the EPA proposed to designate as hazardous two highly prevalent manufactured chemicals known as per- and polyfluoroalkyl substances (PFAS): perfluorooctanoic acid (PFOA) and perfluorooctanesulfonic acid (PFOS). If finalized, the rulemaking would require entities to report to regulators releases of PFOA and PFOS above reportable quantities, and the rulemaking is likely to culminate in new cleanup obligations for these chemicals. In the future, the Partnership could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

Clean Water Act

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. Litigation surrounding this rule is ongoing. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non–compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, the Partnership may be liable for penalties and cleanup and response costs. The federal Clean Water Act only regulates surface waters. However, most of the state analogs to the Clean Water Act also regulate discharges which impact groundwater.

In 2018, the EPA commenced a management study of oil and gas extraction wastewater from both conventional extraction and unconventional extraction such as hydraulic fracturing. The purpose of this study is to understand if support exists for new regulations that would allow for a broader discharge of oil and gas extraction wastewater directly to surface waters under the Clean Water Act’s National Pollutant Discharge Elimination System, in addition to the primary existing disposal methods of underground injection or discharge to centralized wastewater treatment facilities. The EPA produced a report of its findings in May 2020, which did not announce any new regulatory requirements regarding oil and gas extraction wastewater.

In April 2020, the EPA and the U.S. Army Corps issued a navigable waters protection rule under the Clean Water Act, narrowing the definition of “waters of the United States” for which discharge permits would be required during development. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the new rule. Based on this ruling, the EPA and the U.S. Army Corps proposedfinalized in December 20212022 a rule that in practice would restorerestores the old definition.definition and will be effective in March 2023. To the extent that any future rules expand the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for activities in jurisdictional waters of the United States, including wetlands.

Safe Drinking Water Act and Hydraulic Fracturing

Many of the properties the Partnership owns will require additional drilling operations to fully develop the reserves attributable to the properties. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except for fracturing activities involving the use of diesel).

In prior sessions, Congress has considered legislation to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. This legislation has not passed. A number of states, local and regional regulatory authorities have or are considering hydraulic fracturing regulation and other regulations imposing new or more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations or restricting or banning hydraulic fracturing. Further, the EPA has issued an effluent limitations guideline prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned treatment plants.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase the Partnership’s costs of compliance and business.

If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where the Partnership owns properties that require additional drilling, the Partnership could incur substantial compliance costs and such requirements could adversely delay or restrict its ability to conduct fracturing activities on its assets. In December 2017, the Bureau of Land Management (“BLM”) rescinded its own rule from 2015 that would have required oil and gas companies to seek approval from BLM before conducting hydraulic fracturing operations on public lands and for companies to disclose the chemicals used in fracking fluid.

Oil Pollution Act

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge on properties it owns, the Partnership may be liable for costs and damages.

Air Emissions

The operations of the Partnership’s operators are subject to the federal Clean Air Act, or CAA, and analogous state laws and local ordinances governing the control of emissions from sources of air pollution. The CAA and analogous state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (or toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or seek injunctive relief, requiring the Partnership to forego construction, modification or operation of certain air emission sources.

On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation. The EPA rules include standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards required owners/operators to reduce volatile organic compound, or VOC, emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of “green completions.” The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations established specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment.

In August 2020, the EPA finalized a rule that removed sources in the transmission and storage segment from regulation under the 2012 and 2016 New Source Performance Standards (“NSPS”) for the oil and natural gas industry for ozone-forming VOCs and for greenhouse gases (“GHGs”) from methane. On June 30, 2021, President Biden signed into law a joint resolution of Congress disapproving this final rule. The resolution hashad the effect of reinstating the 2012 and 2016 VOC and methane standards for the transmission and storage segment, as well as the methane standards for the production and processing segments.

Further, on November 2, 2021 the EPA proposed a rule to significantly reduce methane emissions from both existing and future oil and gas operations. In November 2022, the EPA proposed a supplemental rule that significantly expands on the November 2021 proposal. The proposedNovember 2022 rule has not yet been finalized.requires additional reductions of methane and VOC emissions from new, modified or reconstructed oil and natural gas facilities and includes first-time presumptive standards for existing oil and gas facilities.

In addition, the new proposal introduces a monitoring approach that would ensure all well sites are regularly monitored for leaks, also known as “fugitive emissions.” Wellhead-only sites would no longer be excluded. The new proposal would base the type and frequency of monitoring on the amount and types of equipment at a site, rather than on estimated emissions from a site. Control devices would be subject to continuous monitoring and regular inspections. EPA is also proposing to limit the use of flares for eliminating venting of associated gas from oil wells, and instead would require well owners/operators to route associated gas to a sales line, use the gas for fuel or another beneficial purpose, or reinject it into a well.

The August 2020 rule also made technical amendments to the fugitive emissions monitoring requirementsrules proposed in the 2016 NSPS for the oilNovember 2021 and natural gas industry that included: changes to the frequency for monitoring fugitive emissions (also known as “leaks”) at well sites and compressor stations, requirements for pneumatic pumps at well sites, and reduced requirements for professional engineer certifications. The technical amendments remain in effect.2022 have not yet been finalized.

In November 2018, the EPA revised a previously stayed rule defining site aggregation for air permitting purposes. Under this rule, it is possible that some sites could require additional permitting under the Clean Air Act, an outcome that could result in costs and delays to the Partnership’s operations.

On November 18, 2016, the BLM published a final rule that was intended to reduce waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on onshore Federal and Indian leases. Unlike the somewhat overlapping EPA regulations, which apply to new, modified and reconstructed sources, the BLM’s 2016 rule was drafted to address existing facilities, including a substantial number of existing wells that are likely to be marginal or low-producing, including leak detection and repair and other requirements regarding methane emissions. BLM’s rule was challenged and struck down in federal court in 2020. It has been reportedIn November 2022, the BLM proposed a new rule that as part of an administration-wide effortlimits monthly royalty-free natural gas flaring at wells on federal and tribal lands and strengthens requirements to reduce methane emissions, BLM will propose new regulations to target methanemitigate waste prevention from oil and gas activities on federally leased lands,these wells, including through possible royalty adjustments. the implementation of a leak detection and repair program.

In addition,November 2021, the Department of Transportation has proposed standards aimed at reducingfinalized rules that brought, for the first time, significant miles of natural gas gathering pipelines under federal safety regulation and imposed new requirements to report incidents, including methane leaks, from these pipelines.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All proposed exploration and development plans on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

The Trump administration EPA issued regulations that significantly changed how a NEPA analysis is conducted. Key changes included eliminating cumulative impact analysis, revising the definition of effects, narrowing what actions are subject to NEPA review, and allowing project proponents a greater role in the environmental review of their own projects. In October 2021,April 2022, the Biden administration proposedfinalized a rule that purports to reversereverses most of the rollbacks introduced through thesethe Trump-era regulations. The administration has suggested that it will introduce a second phasenew revisions represent the first of rules intended to expand the scopetwo phases of NEPA review.rulemaking planned by the Biden administration, and focus on: providing agencies with more flexibility to define the purpose and need of a proposed action; establishing NEPA procedures as a floor rather than a ceiling; and restoring and clarifying the definitions of direct, indirect, and cumulative effects to include environmental impacts related to climate change and environmental justice.

Climate Change Legislation

More stringent laws and regulations relating to climate change and GHG emissions may be adopted in the future and could cause the Partnership to incur material expenses in complying with them. Both houses of Congress have considered legislation to reduce emissions of GHGs, but no legislation has yet passed. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.

The EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries including onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities.

The Biden administration has declared efforts to manage and control climate change a priority, evidenced by the immediate re-commitment of the United States to the Paris Agreement. It is possible this will result in additional federal initiatives to regulate greenhouse gas emissions. In January 2021, the Trump administration EPA issued a rule requiring the EPA to find that an individual industry, such as the power sector or oil and gas operators, collectively emits at least 3% of total U.S. greenhouse gases before setting emissions controls. Only the electric power sector would satisfy that requirement, according to the EPA’s own calculations. The Biden administration succeeded in its court petition to have this rule vacated and remanded.

Nonetheless, because of the lack of any comprehensive legislative program addressing GHGs, there is still a great deal of uncertainty as to how and whether federal regulation of GHGs might take place. In October 2021,June 2022, in a case called West Virginia v. U.S. Environmental Protection Agency, the United States Supreme Court decidedheld that the “major questions” doctrine limits EPA’s power to consider a case that can potentially reshape the scope of the EPA's authority to regulatecurtail GHG emissions under the federal Clean Air Act.by requiring power plants to shift generation to lower emitted fuel sources. The case involvesinvolved a challenge by Republican-led states and coal companies to a federal court ruling that struck down a Trump-era EPA rule that relaxed GHG requirements for power plants.

Prior to this Supreme Court decision, the Biden administration EPA had indicated that it was preparing a new strategy for regulation of GHGs. Even after this decision, EPA has committed to using the full scope of its authority to combat climate change. Among other things, in September 2022 EPA initiated a pre-proposal docket for public input on how to regulate GHG emissions from new and existing fuel-fired plants, with comments due in March 2023. Nevertheless, any significant federal agency effort to introduce new regulations limiting GHG emissions is likely to continue to be challenged in the courts.

In addition to possible federal regulation, a number of states, individually and regionally as well as some localities, also are considering or have implemented GHG regulatory programs or other steps to reduce GHG emissions. These potential regional, state and local initiatives may result in so-called cap and trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in the Partnership incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from its operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas the Partnership produces. The impact of such future programs cannot be predicted, but the Partnership does not expect its operations to be affected any differently than other similarly situated domestic competitors.

Endangered Species Act

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The Partnership’s operators may conduct operations on oil and natural gas leases that have species that are listed and species that could be listed as threatened or endangered under the act. The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to use of the land and may materially delay or prohibit land access for oil and natural gas development. It also may adversely impact the value of the affected properties that the Partnership owns. The designation of previously unprotected species as threatened or endangered in areas where the Partnership might conduct operations could result in limitations or prohibitions on its activities and could adversely impact the value of its leases.

In August 2019, the Fish and Wildlife Service finalized revisions to ESA regulations that in part removed the requirement that listing, delisting or reclassification of species be made “without reference to possible economic or other impacts of such determination.” The rules also relaxed the protection afforded to species listed as “threatened” from those that are endangered, with the protection for “threatened” species being made on more of a case-by-case basis. In OctoberJune 2021, the Fish and Wildlife Service under the Biden administration issued proposed rules effectivelystated its plan to reverserescind or revise most of thesethe 2019 revisions. As of the end of 2022, some of this revisionary rulemaking had been completed while others were ongoing. Pursuant to a number of federal court rulings in 2022, any unamended 2019 Trump-era relaxations.rules under the ESA are expected to remain in place until the Fish and Wildlife Service changes them, which changes the agency expects to finalize in 2024.

OSHA and Other Laws and Regulation

The Partnership is subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right–to–know regulations under Title III of CERCLA and similar state statutes require that the Partnership organize and/or disclose information about hazardous materials used or produced in the Partnership’s operations.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state, local and tribal authorities. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential for financial sanctions for noncompliance. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the Partnership’s cost of doing business and, consequently, affects the Partnership’s profitability, these burdens generally do not affect the Partnership any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production

Statutes, rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted, making difficult the prediction of future costs or the impact of regulatory compliance attributable to new laws and statutes. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects its profitability. The drilling and production operations performed by the Partnership’s contracted operators are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which the Partnership operates also regulate one or more of the following:

State and federal regulations are generally intended to prevent waste of oil and natural gas, protect correlative rights to produce oil and natural gas between owners in a common reservoir or formation, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and natural gas plants operated by other companies that provide midstream services to the Partnership are also subject to the jurisdiction of various federal, state and local authorities, which can affect the Partnership’s operations. State laws also regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties.

States generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within their respective jurisdictions. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

In addition, a number of states, such as North Dakota where the Partnership’s properties are located, and some tribal nations have enacted surface damage statutes, or SDAs. These laws are designed to compensate for damage caused by oil and natural gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and require specific payments by the operator to surface owners/users in connection with exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

The Partnership will not control the availability of transportation and processing facilities that may be used in the marketing of its production. For example, the Partnership may have to shut–in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If the Partnership conducts operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by BLM, Bureau of Safety and Environmental Enforcement, Bureau of Indian Affairs, tribal or other appropriate federal, state and/or Indian tribal agencies.

The Mineral Leasing Act of 1920, or the Mineral Act, prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. The Partnership qualifies as an entity formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non–reciprocal countries, there are presently no such designations in effect. It is possible that the holders of the Partnership’s common units may be citizens of foreign countries and do not own their common units in a U.S. corporation or even if such interest is held through a U.S. corporation, their country of citizenship may be determined to be non–reciprocal countries under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by the Partnership could be subject to cancellation based on such determination.

Federal Regulation of Oil, Natural Gas and Natural Gas Liquids, including Regulation of Transportation

The availability, terms and cost of transportation service significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). The intrastate transportation, local distribution and retail sale of natural gas generally are subject to state regulation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act (“NGA”) as well as under Section 311 of the Natural Gas Policy Act of 1978.

Under FERC’s current regulatory regime, interstate natural gas transportation services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Among other things, the FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC.

FERC also authorizes the construction and operation of interstate natural gas pipelines under Section 7 of the NGA. With respect to its review of applications for the construction and operation of interstate natural gas pipeline facilities under the NGA, FERC must comply with environmental review requirements of NEPA. In 2021, FERC issued a Notice of Inquiry (NOI) requesting public comment on whether it should revise its approach under its current policy statement on certification of new natural gas transportation facilities, including among other things, options for assessing the significance of the impacts of greenhouse gas (GHG) emissions. This NOI is pending before FERC. Also in 2021, in an individual pipeline certificate proceeding, FERC announced that, upon reconsideration of its prior position, it will assess the significance of a proposed pipeline project’s GHG emissions and those emissions’ contribution to climate change in fulfilling its obligations under NEPA.

Wellhead natural gas sale prices are unregulated. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices. The Partnership cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the properties the Partnership owns.

Sales of the Partnership’s oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act (“ICA”). The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. In 2017, FERC issued a declaratory holding that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the (higher) filed tariff rate, would violate the ICA. Rehearing of this order is pending before FERC.

Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to the Partnership’s costs of transporting gas to point-of-sale locations.

The pipelines used to gather and transport natural gas being produced by the Partnership are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk–based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet.

Transportation of the Partnership’s oil, natural gas liquids and purity components (ethane, propane, butane, iso–butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations, including Emergency Orders by the FRA. Revisions to PHMSA gathering line regulations and liquids pipelines regulations could result in the Partnership incurring significant expenses.

Exports of US Oil Production and Natural Gas Production

At the end of 2015, the U.S. Congress voted to end a decades-old prohibition of exports of oil produced in the lower 48 states of the U.S. Under the NGA, the U.S. Department of Energy (“DOE”) authorizes exports of U.S.-produced natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico and Canada. Under the NGA, FERC authorizes the construction and operation of natural gas pipeline facilities crossing the U.S. border used to export U.S.-produced natural gas. In addition, under the NGA, the DOE authorizes the export of liquefied natural gas (“LNG”) through LNG export facilities, while FERC authorizes the siting and construction of onshore and near-shore LNG export terminals. In 2020, DOE issued a Final Policy Statement discontinuing its practice of granting a standard 20-year export term for long-term authorizations to export domestically produced natural gas from the lower-48 states to countries with which the U.S. has not entered into a free trade agreement providing for national treatment for trade in natural gas (“Non-FTA Countries”), and adopting a term through December 31, 2050, as the standard export term for long-term Non-FTA authorizations. Under DOE’s Policy Statement, holders of existing Non-FTA authorizations may file an application with DOE requesting to amend its authorization to extend its export term through December 31, 2050.

Other Regulation

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. The Partnership does not believe that compliance with these laws will have a material adverse effect upon its operations.

Employees

The Partnership has no officers, directors or employees. Instead, the General Partner manages the day-to-day affairs of the Partnership, and all decisions regarding the management of the Partnership are made by the Board of Directors of the General Partner and its officers. The General Partner utilizes the services of qualified third parties and consultants for specific projects, such as the preparation of the Partnership’s reserve estimates. The Board of Directors of the General Partner does not receive any salary, bonus or consulting fees for serving on the board of directors or managing the Partnership’s business. For more detail, refer to Part III, Items 10, 11 and 13, respectively, of this Form 10-K.

General Corporate Information

Energy 11, L.P. is a Delaware limited partnership founded in 2013 with principal offices at 120 W 3rd Street, Suite 220, Fort Worth, Texas 76102. The Partnership’s phone number is (817) 882-9192 and its website address is www.energyeleven.com. The Partnership makes available, free of charge through its Internet website, its annual report on Form 10-K and quarterly reports on Form 10-Q, and amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after the Partnership electronically files such material with, or furnishes it to, the SEC. Information contained on the Partnership’s website is not incorporated by reference into this report.

Item 1A.Risk Factors

Risks Related to the Partnership’s Business, Financial Condition, Results of Operations and Cash Flows

If oil, natural gas or other hydrocarbon prices decrease and/or remain depressed for a prolonged period, such as the period experienced in 2020 upon the onset of the COVID-19 pandemic, cash flows from operations will decline and cash available for distributions will be impacted.

The Partnership’s revenue, profitability and cash flow depend upon the prices for oil, natural gas and other hydrocarbons. The prices the Partnership will receive for its production will be volatile and a drop in prices can significantly affect its financial results and adversely affect the Partnership’s ability to obtain credit, maintain its borrowing capacity and to repay indebtedness, all of which can affect the Partnership’s ability to pay distributions. Changes in prices have a significant impact on the value of the Partnership’s reserves and on its cash flows. Prices may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond the Partnership’s control, such as:

Decreased oil, natural gas and other hydrocarbon prices will decrease Partnership revenues, and may also reduce the amount of oil, natural gas or other hydrocarbons that the Partnership can economically produce. If decreases occur, or if estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require the Partnership to write down, as a non–cash charge to earnings, the carrying value of its oil and natural gas properties for impairments. The Partnership is required to perform impairment tests on its assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. The Partnership may incur impairment charges in the future, which could have a material adverse effect on its results of operations in the period taken and the Partnership’s ability to borrow funds under a credit facility, which may adversely affect the Partnership’s ability to make cash distributions to holders of its common units and service its debt obligations.

The Partnership may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to the General Partner, to enable the Partnership to make cash distributions to holders of its common units under its cash distribution policy.

The Partnership may not have sufficient available cash each month to enable it to make cash distributions to the holders of common units. The amount of cash the Partnership can distribute on its common units principally depends upon the amount of cash the Partnership generates from its operations, which will fluctuate from month to month based on, among other things:

In addition, the actual amount of cash the Partnership will have available for distribution will depend on other factors, some of which are beyond the Partnership’s control, including:

As a result of these factors, the amount of cash the Partnership distributes to holders of its common units may fluctuate significantly from month to month.

The Partnership has limited control over the activities on its properties.

At December 31, 2021, Whiting2022, Chord operates 98%substantially all of the properties in which the Partnership holds a working interest. The Partnership has limited ability to influence or control the operation or future development of the non-operated properties or the amount of capital expenditures that it is required to fund. The failure of Whiting,Chord, or the Partnership’s other operators,operator, to adequately perform operations, to comply with the applicable agreements or to act in ways that are in the Partnership’s best interest could reduce the Partnership’s production and revenues. The Partnership’s dependence on WhitingChord and other working interest owners for these projects and the Partnership’s limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of the Partnership’s targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

The Partnership participates in oil and gas leases with third parties who may not be able to fulfill their commitments to the Partnership’s projects.

The Partnership owns less than 100% of the working interest in the Sanish Field Assets, and other parties own the remaining portion of the working interests. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person or entity. The Partnership could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of the other working interest owners, particularly those that are smaller and less established, will not be able to fulfill their joint activity obligations. Another working interest owner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy. In the event any of the Partnership’s co-owners do not pay their share of such costs, the Partnership would likely have to pay its share of those costs, and the Partnership may be unsuccessful in any efforts to recover these costs from its partners, which could materially adversely affect the Partnership’s financial position.

The Partnership’s results from operations may be impacted by a lack of geographical diversification.

All of the Partnership’s assets are located in concentrated areas of the Williston Basin in Mountrail County, North Dakota. While other companies and limited partnerships may have the ability to manage their risk by diversification, the narrow geographic focus of the Partnership’s business means that it may be impacted more acutely by factors affecting its industry or the region in which the Partnership operates than it would if its asset locations were more diversified. The Partnership may be disproportionately exposed to the effects of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of oil or natural gas. Additionally, the Partnership may be exposed to further risks, such as changes in field-wide rules and regulations that could cause the Partnership to permanently or temporarily shut-in all of its wells within the Williston Basin. The Partnership does not currently intend to broaden the geographic scope of its asset base.

The Partnership depends on oil and natural gas transportation and processing facilities and other assets that are owned by third parties.

The marketability of Partnership oil and natural gas depends in part on the availability, proximity and capacity of pipeline systems, processing facilities, oil trucking fleets and rail transportation assets owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, physical damage, scheduled maintenance, legal or other reasons such as suspension of service due to legal challenges (see below regarding the Dakota Access Pipeline), could result in a substantial increase in costs, the shut-in of producing wells or the delay or discontinuance of development plans for the Sanish Field Assets. The negative effects arising from these and similar circumstances may last for an extended period of time.

The Dakota Access Pipeline (“DAPL”), a major pipeline running out of the Williston Basin, is subject to publicized ongoing litigation that could threaten its continued operation. In July 2020, the U.S. District Court for D.C. (“D.C. District Court”) ruled that the Dakota Access Pipeline, a significant pipeline that transports oil and natural gas from North Dakota fields, must suspend operations due to inadequate environmental review previously performed by the U.S. Army Corps of Engineers. In August 2020, the ruling was stayed on appeal by the U.S. Court of Appeals for the D.C. Circuit (“D.C. Appellate Court”), allowing the pipeline to operate until a further ruling was made. In January 2021, the D.C. Appellate Court affirmed the D.C. District Court’s decision. Further, in May 2021, the D.C. District Court denied an injunction that would have required a shutdown of the Dakota Access Pipeline while the U.S. Army Corps of Engineers completes its comprehensive environmental review. In June 2021, the D.C. District Court dismissed the existing claims against the Dakota Access Pipeline and its operators, but stated the plaintiffs could renew challenges against the pipeline after the U.S. Army Corps of Engineers releases its environmental review report. In February 2022, the United States Supreme Court declined to take a case brought by the Dakota Access Pipeline operators that challenged the requirement of an updated environmental review as upheld by lower courts. The U.S. Army Corps of Engineers report which is anticipatedhas yet to be issued in the fall of 2022.issued. A court-ordered shut-down remains possible, and there is no guarantee that DAPL will be permitted to resume or continue operations following the completion of the environmental review or any outstanding litigation.

Any significant curtailment in gathering system or pipeline capacity, or the unavailability of sufficient third-party trucking or rail capacity, could adversely affect the Partnership’s results of operations and financial condition.

The Partnership and the operators of its properties may encounter obstacles to marketing the Partnership’s share of oil, natural gas and other hydrocarbons, which could adversely impact the Partnership’s revenues.

The marketability of the Partnership’s production will depend upon numerous factors beyond the Partnership’s control, including the availability and capacity of natural gas gathering systems, pipelines and other transportation and processing facilities owned by third parties. Transportation space on the gathering systems and pipelines the Partnership expects to utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. The Partnership’s access to transportation and processing options and the marketing of the Partnership’s production can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, as well as the other risks discussed above. The availability of markets is beyond the Partnership’s control. If market factors dramatically change, the impact on the Partnership’s revenues could be substantial and could adversely affect the Partnership’s ability to produce and market oil, natural gas and natural gas liquids, the value of the Partnership’s common units and the Partnership’s ability to pay distributions on the Partnership’s common units and service the Partnership’s debt obligations.

The Partnership may be required to shut-in wells or delay initial production for lack of a viable market or because of the inadequacy or unavailability of pipeline, gathering system, processing, treating, fractionation or refining capacity. When that occurs, the Partnership will be unable to realize revenue from such wells until the inadequacy or unavailability is remedied. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

The Partnership may need additional funding for the Sanish Field Assets in order to retain its full interest therein.

The Partnership anticipates that it will be obligated to significantly invest in drilling capital expenditures within the next five years to participate in drilling activity in the Sanish Field Assets without becoming subject to non-consent penalties under the joint operating agreements governing those properties. The Partnership will depend, at least in part, on cash flow from operations and/or availability under its Credit Facilitycredit facility to fund the anticipated capital expenditures needed to retain its full interest in the Sanish Field Assets. None of these funding sources is guaranteed, and if the Partnership is unable to obtain all of this funding, it may lose all or a portion of the assets acquired, and the Partnership’s results of operations will be negatively affected accordingly.

Property interests that the Partnership has purchased or of which the Partnership participates in the development may not produce as projected and the Partnership may be unable to realize reserve potential, which could adversely affect the Partnership’s cash available for distribution.

The Partnership’s completed acquisitions and any decision to participate in the development of a property the Partnership owns required or will require an assessment of recoverable reserves, title, future oil, natural gas and natural gas liquids prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and similar factors. Reserve estimates may be prepared by the operators or third parties for the operators of properties. The Partnership has engaged and may engage its own third-party petroleum engineers to review such reserve estimate reports and provide the Partnership with an independent assessment of the reserve estimates. The process of estimating oil and gas reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors such as future oil and gas prices, drilling and operating expenses, capital expenditures, taxes and the availability of funds, all of which can be difficult to predict with accuracy. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact the Partnership’s financial conditions and results of operations and its ability to make cash distributions to holders of its common units and service its debt obligations.

Additional potential risks at the acquisition date and those related to development include, among other things:

The Partnership could experiencehas experienced higher costs in 2022 due to inflation having widespread effects on the economy. Sustained periods of higher costs if oil and natural gas prices rise or as drilling activity otherwise increases in the Partnership’s area of operations. Higher costs could reduce the Partnership’s profitability and cash flow.

Historically, capital and operating costs typically rise during periods of sustained increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond the Partnership’s control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that the Partnership and its vendors will rely upon, and the cost of services and labor especially those required in horizontal drilling and completion. Historically, oil and natural gas prices have fluctuated resulting in fluctuating levels of drilling activity in the U.S. oil and natural gas industry. Lower prices typically lead to lower costs of some drilling and completion equipment, services, materials and supplies. As commodity prices rise or stabilize or drilling activity otherwise increases, these lower cost levels may not be sustainable over long periods. As a result, such costs may rise faster than selling prices thereby negatively impacting the Partnership’s profitability and cash flow.

The Partnership’s hedging transactions will expose it to counterparty credit risk.

Historically, the Partnership has engaged in hedging transactions to reduce, but not eliminate, the effect of volatility in oil, gas and other hydrocarbon prices. The Partnership may also engage in hedging transactions in future periods. Hedging transactions will expose the Partnership to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the derivative contract. The Partnership is unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if the Partnership does accurately predict sudden changes, its ability to negate the risk may be limited depending upon market conditions.

During periods of falling commodity prices, such as those that occurred in late 2008, 2012 and early 2020, the Partnership’s hedge receivable positions will increase, which increases the Partnership’s exposure. If the creditworthiness of the Partnership’s counterparties deteriorates and results in their nonperformance, the Partnership could incur a significant loss.

The Partnership’s hedging activities could result in financial losses or could reduce the Partnership’s net income, which may adversely affect the Partnership’s ability to pay cash distributions to holders of its common units.

To achieve more predictable cash flows and to reduce the Partnership’s exposure to fluctuations in the prices of oil, natural gas and other hydrocarbons, the Partnership has and may enter into hedging arrangements for a significant portion of its estimated future production. If the Partnership experiences a sustained material interruption in its production, the Partnership might be forced to satisfy all or a portion of its hedging obligations without the benefit of the cash flows from the Partnership’s sale of the underlying physical commodity, resulting in a substantial diminution of its liquidity.

The Partnership’s ability to use hedging transactions to protect it from future price declines will be dependent upon oil and natural gas prices at the time the Partnership enters into hedging transactions and the Partnership’s future levels of hedging, and as a result its future net cash flows may be more sensitive to commodity price changes. Additionally, it may not be possible or economic to hedge all of the hydrocarbons the Partnership produces because of the lack of a market for such hedges or other reasons. The Partnership may hedge certain hydrocarbons it produces by entering into swaps, collars or other contracts covering hydrocarbons the Partnership considers to be priced similarly to the hydrocarbons it produces, and could be subject to losses if the prices for the hydrocarbons the Partnership produces do not match the hydrocarbons for which the Partnership contracts.

The Partnership’s policy is to hedge a portion of its near–term estimated production. The prices at which the Partnership hedges its production in the future will be dependent upon commodity prices at the time the Partnership enters into these transactions, which may be substantially higher or lower than current oil, natural gas and other hydrocarbon prices. Accordingly, the Partnership’s price hedging strategy may not protect it from significant declines in oil and natural gas prices received for its future production. Conversely, the Partnership’s hedging strategy may limit its ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of the Partnership’s future production will not be hedged as compared with the next few years, which would result in its oil, natural gas and natural gas liquids revenues becoming more sensitive to commodity price changes. The General Partner will not be liable for any losses the Partnership incurs as a result of the Partnership’s hedging policy or the implementation of that policy.

The Partnership plans to rely on drilling to fully develop the properties the Partnership has acquired.If drilling is unsuccessful, the Partnership’s cash available for distributions and financial condition will be adversely affected.

The Partnership has acquired oil and natural gas properties that are not fully developed, and require that the Partnership engagesengage in drilling to fully exploit the reserves attributable to the properties. The Partnership’s drilling, completed by its operators, will involve numerous risks, including the risk that the Partnership will not encounter commercially productive oil or natural gas reservoirs. The Partnership may incur significant expenditures to drill and complete wells, including cost overruns. Additionally, current geoscience technology may not allow the Partnership to know conclusively, prior to drilling a well, that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and it is possible that the Partnership will make substantial expenditures on drilling and not discover reserves in commercially viable quantities. These expenditures will reduce cash available for distribution to holders of the Partnership’s common units and for servicing any debt obligations.

The Partnership’s drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

Even if drilled, completed wells may not produce quantities of oil or natural gas that are economically viable or that meet earlier estimates of economically recoverable reserves. A productive well may become uneconomic if water or other deleterious substances are encountered, which impair or prevent the production of oil and/or natural gas from the well. The Partnership’s overall drilling success rate or drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in the Partnership’s production and revenues and materially harm its operations and financial condition by reducing available cash and resources.

The Partnership’s continued success depends upon its ability to develop oil and gas reserves that are economically recoverable.

In addition, the Partnership’s future oil and natural gas production will depend on the Partnership’s success developing its assets to add to its reserves. If the Partnership is unable to replace reserves through drilling, the Partnership’s level of production and cash flows will be adversely affected. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. The Partnership’s total proved reserves decline as reserves are produced unless the Partnership conducts other successful development activities. The Partnership’s ability to make the necessary capital investment to maintain and expand its asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. The Partnership may not be successful in developing its assets to increase its reserves.

The Partnership’s business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect the Partnership’s financial condition or results of operations and, as a result, the Partnership’s ability to pay distributions to holders of its common units and service its debt obligations.

The Partnership’s business activities are subject to operational risks, including:

Any of these events could adversely affect the Partnership’s ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension or cessation of operations, and attorneys’ fees and other expenses incurred in the prosecution or defense of litigation and could also result in requirements to remediate, regulatory investigations, and/or the interruption of the Partnership’s business and/or the business of third parties.

As is customary in the industry, the operator of the properties maintains insurance against some but not all of these risks. The Partnership may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on the Partnership’s business activities, financial condition, results of operations and ability to pay distributions to holders of its common units and service its debt obligations.

Risks Related to Investment in the Partnership

The Partnership depends on key personnel, the loss of any of whom could materially adversely affect future operations.

The Partnership’s success will depend to a large extent upon the efforts and abilities of Messrs. Knight, McKenney, Keating and Mallick, the executive officers of the General Partner. The loss of the services of one or more of these key employees could have a material adverse effect on the Partnership. The Partnership does not maintain key-man life insurance with respect to any employees. The Partnership’s business will also be dependent upon its ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause the Partnership to incur greater costs or prevent it from pursuing its acquisition and development strategy as quickly as the Partnership would otherwise wish to do.

The common units are not liquid and a limited partner’s ability to resell common units will be limited by the absence of a public trading market and substantial transfer restrictions.

The common units generally will not be liquid because there is not a readily available market for the sale of common units, and one is not expected to develop. Further, although the Partnership Agreement contains provisions designed to permit the listing of common units on a national securities exchange, the Partnership does not currently intend to list the common units on any exchange or in the over-the-counter market.

Distributions to the Partnership’s common unitholders may not be sourced from its cash generated from operations but from indebtedness, and therefore the Partnership’s distributions during certain periods may exceed earnings and cash flows from operations, and this will decrease the Partnership’s distributions in the future; furthermore, the Partnership cannot guarantee that investors will receive any specific return on their investment.

The General Partner has the right to make distributions from the proceeds of borrowings and capital contributions. Offering proceeds that are returned to investors as part of distributions to them will not be available for investments in oil and natural gas properties. In addition, during certain periods, distributions may exceed the amount of earnings and cash flows from operations during such periods. The payment of distributions will decrease the cash available to invest in the Partnership’s oil and natural gas properties and will reduce the amount of distributions the Partnership may make in the future. The Partnership cannot and does not guarantee that investors will receive any specific return on their investment.

Moreover, a portion of the Partnership’s cash flow is used to pay interest on its BancFirst Credit Facility. Interest and principal payments on the Credit Facility will reduce the cash available to finance the Partnership’s operations and other business activities and could limit the Partnership’s flexibility in planning for or reacting to changes in the Partnership’s business and the industry in which it operates.

If the General Partner elects to cause the Partnership to make distributions rather than reinvesting the cash flow in its business, the Partnership may be required to sell or farm-out properties or to elect not to participate in exploration or development drilling activities on its properties, which activities could turn out to be profitable.

If the Partnership were presented with an exploration or development drilling or other opportunity on its properties, and funding the opportunity would require the Partnership’s cash that is required to be distributed to limited partners in order to follow its distribution policy or for other purposes approved by the General Partner, the General Partner may elect to cause the Partnership to sell or farm-out the opportunity or decline to participate in the opportunity, even if the General Partner determines that the opportunity could have a favorable rate of return. The General Partner will have the right to cause the Partnership to participate in opportunities that will use the Partnership’s cash otherwise than in accordance with the distribution policy if the General Partner determines that pursuing such opportunity is in the best interests of the Partnership.

The General Partner will be subject to conflicts of interest in operating the Partnership, including conflicts of interest arising out of the General Partner’s ownership of the incentive distribution rights. The Partnership Agreement limits the General Partner’s fiduciary duties to the Partnership in connection with these conflicts of interest.

The General Partner is subject to conflicts of interest in operating the Partnership’s business. These conflicts include:

The Partnership Agreement provides that the General Partner will have no liability to the Partnership or the holders of the common units for decisions made, if such decisions are made in good faith. In addition, the Partnership Agreement provides that if the General Partner receives a fairness opinion regarding the sale price of a property or in connection with a merger or the listing of the Partnership’s common units on a national securities exchange, including transactions that involve affiliates of the General Partner, the General Partner will be deemed to have acted in good faith.

The General Partner has sole responsibility for conducting the Partnership’s business and managing its operations. The General Partner and its affiliates will have conflicts of interest, which may permit them to favor their own interests to the detriment of holders of the Partnership’s common units.

Conflicts of interest may arise between the General Partner and its respective affiliates on the one hand, and the Partnership and the holders of its common units, on the other hand. In resolving these conflicts of interest, the General Partner may favor its own interests and the interests of its owners over the interests of holders of the Partnership’s common units. These conflicts include, among others, the following situations:

Amounts paid to the General Partner, regardless of success of the Partnership’s activities, will reduce the cash the Partnership has available for distribution.

The General Partner and its affiliates have and will receive reimbursement of third-party costs incurred in connection with the Partnership’s business activities and will be reimbursed for general and administrative costs of the General Partner allocable to the Partnership as described in “Compensation” within the Partnership’s prospectus, regardless of the Partnership’s success in acquiring, developing and operating properties. The fees and direct costs to be paid to the General Partner will reduce the amount of cash distributions to investors. With respect to third-party costs, the General Partner has sole discretion on behalf of the Partnership to select the provider of the services or goods and the provider’s compensation.

Because the General Partner has discretion to determine the amount and timing of any distribution the Partnership may make, there is no guarantee that cash distributions will be paid by the Partnership in any amount or frequency even if its operations generate revenues.

The timing and amount of distributions will be determined in the sole discretion of the General Partner. The level of distributions, when made, will primarily be dependent upon the Partnership’s levels of revenue, among other factors. Distributions may be reduced or deferred, in the discretion of the General Partner, to the extent that the Partnership’s revenues are used or reserved for any of the following:

Further, because the Partnership’s investments will be in depleting assets, unless reinvested, Partnership revenues and the amount available for distribution to partners will decline with the passage of time. Accordingly, there can be no assurance that the Partnership will be able to make regular distributions or that distributions will be made at any consistent rate or frequency.

The Partnership may be unable to sell its properties, merge with another entity or list the common units on a national securities exchange within its planned timeline or at all.

Approximately five to seven years after the termination of the Partnership’s public offering, the Partnership plans either to sell its properties and distribute the proceeds of the sale, after payment of liabilities and expenses, to its partners; merge with another entity; or list the common units on a national securities exchange. The decision to sell the Partnership’s properties or merge with another entity will be based on a number of factors, including the domestic and foreign supply of and demand for oil, natural gas and other hydrocarbons, commodity prices, demand for oil and natural gas assets in general, the value of the Partnership’s assets, the projected amount of the Partnership’s oil and gas reserves, general economic conditions and other factors that are out of the Partnership’s control. In addition, the ability to list the Partnership’s common units on a national securities exchange will depend on a number of factors, including the state of the U.S. securities markets, the Partnership’s ability to meet the listing requirements of national securities exchanges, securities laws and regulations and other factors. If the Partnership is unable to either sell its properties, merge or list the common units on a national securities exchange in accordance with its current plans, youlimited partners may be unable to sell or otherwise transfer your common units and youlimited partners may lose some or all of yourtheir investment. While the Partnership plans to seek a liquidity event within five to seven years, theThe Partnership Agreement does not obligate the General Partner to cause a liquidity event within thata particular timeline. The timing of a liquidity event will be dependent upon many factors, including prevailing market conditions, and the Partnership Agreement gives the Partnership flexibility on timing so that the Partnership is not forced to act during periods of low oil and gas prices, or other disadvantageous situations.

The General Partner may cause the Partnership not to participate with the operator in the drilling of wells on the Partnership’s properties.

If the Partnership has the opportunity to participate in wells, the General Partner may decide to sell or farmout the well. Also, if a well is proposed under an operating agreement for one of the properties the Partnership owns, the General Partner may cause the Partnership to “non-consent” the well under the applicable operating agreement. Non-consenting a well will generally cause the Partnership not to be obligated to pay the costs of the well, but the Partnership will not be entitled to the proceeds of production from the well until a penalty is received by the parties that drilled the well. If the General Partner makes the decision to sell, farmout or non-consent a well or other development activity, the Partnership Agreement provides that the General Partner will have no liability to the Partnership so long as the decision is made in good faith.

Fees and cost reimbursements that must be paid to the General Partner and the Dealer Manager regardless of success of the Partnership’s activities will reduce the cash the Partnership has available for distribution.

The General Partner and its affiliates have and will receive reimbursement of third-party costs incurred in connection with the Partnership’s business activities and will be reimbursed for general and administrative costs of the General Partner allocable to the Partnership regardless of the Partnership’s success in acquiring, developing and operating properties. The Dealer Manager is eligible to receive the contingent, incentive fee after Payout, as defined in the Prospectus. The fees and direct costs to be paid to the General Partner and the Dealer Manager will reduce the amount of cash distributions to investors.

Risks Related to Laws, Regulations, Cybersecurity and Other External Factors

The Partnership is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting the Partnership’s operations.

The Partnership’s business is subject to complex and stringent laws and regulations governing the acquisition, development, operation, production and marketing of oil and gas, taxation, safety matters and the discharge of materials into the environment. In order to conduct the Partnership’s operations in compliance with these laws and regulations, the operator(s) of the Partnership’s properties must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining and maintaining regulatory approvals or drilling permits could have a material adverse effect on the Partnership’s ability to develop its properties, and receipt of drilling permits with onerous conditions could increase the Partnership’s compliance costs. In addition, regulations or executive orders regarding resource conservation practices and the protection of correlative rights may affect the Partnership’s operations by limiting the quantity of oil, natural gas and natural gas liquids the Partnership may produce and sell.

The Partnership is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil, natural gas and natural gas liquids. While the cost of compliance with these laws is not expected to be material to the Partnership’s operations, the possibility exists that new laws, regulations, executive orders or enforcement policies could be more stringent and significantly increase the Partnership’s compliance costs. If the Partnership is not able to recover the resulting costs through insurance or increased revenues, the Partnership’s ability to pay distributions to holders of the Partnership’s common units and service the Partnership’s debt obligations could be adversely affected.

Federal and state legislative initiatives, including executive orders, relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays, and even could result in the Partnership ceasing business operations.

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from dense rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The operators of the properties the Partnership owns will routinely use hydraulic fracturing techniques in most drilling and completion programs. In past legislative sessions, legislation was introduced before Congress to provide for federal regulation of hydraulic fracturing using materials other than diesel under the Safe Drinking Water Act and to require disclosure of the chemicals used in the fracturing process; this legislation has not passed. At the state and local levels, some jurisdictions have adopted, and others are considering adopting, requirements that could impose more stringent permitting, public disclosure of fracturing chemicals or well construction requirements on hydraulic fracturing activities, as well as bans on hydraulic fracturing activities.

On January 27, 2021, the Biden administration signed an executive order directing the Secretary of the Interior to temporarily stop issuing new oil and gas leases on federal lands, allowing time to review and reset the federal government’s oil and gas leasing program. The Partnership’s existing leases and permits are operational and held by production, and therefore not impacted by this executive order. However, the Biden administration has proceeded to recommend an overhaul of the federal oil and gas leasing program to limit areas available for energy development and raise costs for companies to drill on public land. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Partnership owns producing properties, the Partnership could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from participating in drilling wells. More widespread or prolonged moratoriums or prohibitions of hydraulic fracturing could, depending on the makeup of the Partnership’s assets, cause the Partnership to cease business operations.

Additional regulatory scrutiny by the EPA could make it difficult to perform hydraulic fracturing, impact the Partnership’s ability to conduct business, and increase the Partnership’s costs of compliance and doing business.

Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. The EPA has announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. The EPA also issued a pretreatment standard for the discharge of wastewater resulting from hydraulic fracturing activities, prohibiting the discharges of wastewater pollutants from onshore unconventional oil and gas extraction to publicly owned treatment works. In December 2016, the EPA concluded that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain data gaps and uncertainties limited the EPA’s assessment. The historic trend of more expansive and stricter environmental regulation may continue for the long term. Any additional regulatory actions taken by the EPA could increase the costs of the Partnership’s operations or result in additional operating restrictions or delays. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that the Partnership ultimately is able to produce.

The Partnership’s financial condition and results of operations may be materially adversely affected if the Partnership incurs costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

The Partnership may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of its wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations, including any related to climate change and greenhouse gases, may be adopted in the future. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

Climate change legislation or regulations restricting emissions of greenhouse gases, or GHGs, could result in increased operating costs and reduced demand for the oil, natural gas and natural gas liquids the Partnership produces.

In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. These permitting provisions, to the extent applicable to the Partnership’s operations, could require the operator(s) of the Partnership’s properties to implement emission controls or other measures to reduce GHG emissions and the Partnership could incur additional costs to satisfy those requirements. Further, the EPA has proposed rules to significantly regulate methane emissions from new and existing oil and gas production sources and natural gas processing and transmission sources. The broader recent trend of more expansive and stricter climate change regulation is likely to continue for the long term, including with the Biden administration’s return to the Paris Agreement global treaty to curb greenhouse gas emissions.

In addition, the EPA requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities the Partnership owns. Reporting of GHG emissions from such facilities is required on an annual basis. Should the operator(s) of the Partnership’s properties trigger the reporting requirement, the Partnership will incur costs associated with the reporting obligation.

In past legislative sessions, Congress considered comprehensive federal legislation to reduce emissions of GHGs and many states and regions meanwhile have adopted or have considered measures to reduce GHG emission reduction levels, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. Federal efforts at a cap and trade program have not moved forward in Congress. Some members of Congress have publicly indicated an intention to introduce legislation to curb the EPA’s regulatory authority over GHGs and the United States Supreme Court is considering the issue. The adoption and implementation of any legislation or regulatory programs imposing reporting obligations on, or limiting emissions of GHGs from, equipment and operations on the Partnership’s properties could require the Partnership to incur costs to reduce emissions of GHGs associated with the Partnership’s operations or could adversely affect demand for the oil, natural gas and natural gas liquids that the Partnership produces.

Significant physical effects of climatic change have the potential to damage the Partnership’s facilities, disrupt the Partnership’s production activities and cause the Partnership to incur significant costs in preparing for or responding to those effects.

In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, the operations that the Partnership plans to engage in may be adversely affected. Potential adverse effects could include damages to the Partnership’s facilities from powerful winds or rising waters in low lying areas, disruption of the Partnership’s production activities either because of climate-related damages to the Partnership’s facilities or the Partnership’s costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on the Partnership’s financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom the Partnership has a business relationship. The Partnership may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. Should drought conditions occur, the Partnership’s ability to obtain water in sufficient quality and quantity could be impacted and in turn, the Partnership’s ability to perform hydraulic fracturing operations could be restricted or made more costly.

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact the Partnership’s operations.

The Partnership’s business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. The Partnership depends on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with the general partner and third-party partners. Unauthorized access to the Partnership’s seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in the Partnership’s exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport the Partnership’s production to market. A cyber-attack involving the Partnership’s information systems and related infrastructure, or that of the Partnership’s business associates, could negatively impact the Partnership’s operations in a variety of ways, including but not limited to, the following:

All of the above could negatively impact the Partnership’s operational and financial results. Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period. As cyber threats continue to evolve, the Partnership may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cyber-attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.

Loss of Partnership information and computer systems could adversely affect the Partnership’s business.

The Partnership will be heavily dependent on information systems and computer-based programs of its operators, including well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in the hardware or software network infrastructure, possible consequences include the Partnership’s loss of communication links, inability of the Partnership’s operators to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on the Partnership’s business.

Tax Risks to Limited Partners

The Partnership’s tax treatment depends on its status as a partnership for U.S. federal income tax purposes and not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service treats the Partnership as a corporation or the Partnership becomes subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution to the Partnership’s limited partners.

The anticipated after-tax economic benefit of an investment in the common units depends largely on the Partnership being treated as a partnership for U.S. federal income tax purposes. Despite being organized as a partnership under state law, the Partnership will be treated as a corporation for U.S. federal income tax purposes unless it satisfies the “qualifying income” requirement. Based on the Partnerships current operations, we believe the Partnership satisfies the qualifying income requirement. The Partnership has not requested, and does not plan to request, a ruling from the Internal Revenue Service (“IRS”) on this or any other tax matter affecting it.

If the Partnership was treated as a corporation for U.S. federal income tax purposes, the Partnership would pay federal income tax on the Partnership’s taxable income at the corporate tax rate, which, effective January 1, 2018, is currently a maximum of 21% and likely would pay state income tax at varying rates. Distributions to a limited partner would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to a limited partner. Because a tax would be imposed upon the Partnership as a corporation, cash available for distribution to a limited partner would be substantially reduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flows and after-tax return to the unitholders,limited partners, likely causing a substantial reduction in the value of the Partnership’s common units.

Current law may change so as to cause the Partnership to be treated as a corporation for U.S. federal income tax purposes or otherwise subject the Partnership to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states have ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such taxes on the Partnership will reduce the cash available for distribution to a limited partner.

An IRS contest of the Partnership’s U.S. federal income tax positions may adversely affect the value for the Partnership’s

common units, and the cost of any IRS contest will reduce the Partnership’s cash available for distribution to the Partnership’s

limited partners.

The Partnership has not requested a ruling from the IRS with respect to its treatment as a partnership for U.S. federal income tax purposes or any other matter affecting the Partnership. It may be necessary to resort to administrative or court proceedings to sustain some or all of the Partnership’s counsel’s conclusions or the positions the Partnership takes. A court may not agree with all of the Partnership’s counsel’s conclusions or positions the Partnership takes. Any contest with the IRS may materially and adversely impact the value of the Partnership’s units. In addition, costs incurred in any contest with the IRS will be borne indirectly by limited partners and the General Partner because the costs will reduce the Partnership’s cash available for distribution. In addition, a successful IRS challenge to the Partnership’s U.S. federal income tax positions could adversely affect the amount, character and timing of taxable income or loss allocated to limited partners.

If the IRS makes audit adjustments to the Partnership’s income tax returns, for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from the Partnership, in which case cash available for distribution to limited partners might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, ifIf the IRS makes audit adjustments to the Partnership’s income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from the Partnership. To the extent possible under the newthese rules, the General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if the Partnership is eligible, issue a revised Schedule K-1 to each limited partner with respect to an audited and adjusted return. Although the General Partner may elect to have limited partners take such audit adjustment(s) into account in accordance with their interests in the Partnership during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, the Partnership’s current limited partners may bear some or all of the tax liability resulting from such audit adjustment(s), even if such limited partners did not own units in the Partnership during the tax year under audit. If, as a result of any such audit adjustment, the Partnership is required to make payments of taxes, penalties and interest, cash available for distribution to limited partners might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in Partnership common units by tax-exempt entities, such as individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. For example, much of the Partnership’s income allocated to organizations that are exempt from federal income tax, including IRAs, will be unrelated business income and will be taxable to them. Similarly, much of the Partnership’s income allocable to non-U.S. persons will constitute effectively connected U.S. trade or business income, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of the Partnership’s taxable income. Non-U.S. and tax-exempt limited partners should consult their tax advisors regarding the tax implications to them of on an investment in Partnership’s common units.

A limited partner may be required to pay taxes on income from the Partnership even if a limited partner did not receive any sufficient cash distributions from the Partnership.

Because holders of the Partnership’s common units will be treated as partners to whom the Partnership will allocate taxable income which could be different in amount than the cash the Partnership distributes, a limited partner will be required to pay any federal income taxes and, in some cases, state and local income taxes on its share of the Partnership’s taxable income even if a limited partner receives no cash distributions from the Partnership. A limited partner may not receive cash distributions from the Partnership equal to its share of the Partnership’s taxable income or even equal to the tax liability that results from that income.

A limited partner may not qualify for percentage depletion deductions, and even if a limited partner does so qualify, a limited partner will be required to determine, and maintain records supporting, the deduction.

Percentage depletion is generally available with respect to limited partners who qualify under the independent producer exemption contained in Internal Revenue Code (“Code”) Section 613A(c). For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. The Partnership cannot determine whether, or provide any assurance that, a limited partner will qualify as an independent producer. Further, if a limited partner does qualify as an independent producer, the limited partner is required to determine the amount of the allowed percentage depletion deduction and maintain records supporting such determination.

The Partnership cannot assure its limited partners that it will meet the requirements for its limited partners to deduct intangible drilling and development costs.

Federal tax law places substantial limits on taxpayers’ ability to deduct intangible drilling and development costs (“IDCs”). Generally speaking, an “operator” is permitted to elect to currently deduct, or capitalize and deduct ratably over a 60-month period, costs that are properly characterized as IDCs that the operator incurs in connection with the drilling and development of oil and natural gas wells. For purposes of deducting IDCs, an “operator” is generally defined as one that owns a working or an operating interest in an oil or gas well. If the Partnership determines that it is an “operator” with respect to its oil and gas wells, the Partnership’s determination is not binding on the IRS. The IRS may assert that the Partnership is not an “operator” with respect to one or more of its oil or gas wells at the time that IDCs are incurred. If the IRS were successful in such a challenge, the Partnership and, therefore, its limited partners, would not be entitled to deduct the IDCs incurred in connection with such wells.

If the Partnership is eligible to deduct IDCs, the Partnership cannot assure its limited partners that IDCs will be deductible in any given year.

If the Partnership is deemed to be an operator with respect to one or more of its oil or gas wells, its classification of a cost as an IDC is not binding on the IRS. The IRS may reclassify an item classified by the Partnership as an IDC as a cost that must be capitalized or that is not deductible.

The IRS could challenge the timing of the Partnership’s deductions of IDCs, which could result in an increase to limited partners’ tax liabilities.

IDCs are generally deductible when the well to which the costs relate is drilled. In some cases, IDCs may be paid in one year for a well that is not drilled until the following year. In those cases, the prepaid IDCs will not be deductible until the year when the well is drilled unless (i) drilling on the well to which the prepayment relates starts within 90 days after the end of the year the prepayment is made or (ii) it is reasonable to expect that the well will be fully drilled within 3-1/2 months of the prepayment. All of the Partnership’s wells may not be drilled during the year when the Partnership pays IDCs pursuant to a drilling contract. As a result, the Partnership could fail to satisfy the requirements to deduct the IDCs in the year when paid and/or the IRS may challenge the timing of the Partnership’s deduction of prepaid IDCs.

The deduction for IDCs may not be available to a limited partner if a limited partner does not have passive income.

If a limited partner has invested in the Partnership, the limited partner’s share of the Partnership’s deduction for IDCs in the year the limited partner invested in the Partnership and in future years will be a passive loss that can be used to offset only passive income. Such deductions cannot be used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends and interest income. Any unused passive loss from IDCs may be carried forward indefinitely by a limited partner to offset passive income in subsequent taxable years. Certain taxpayers are not subject to the passive loss rules.

On the disposition of property by the Partnership or of common units by a limited partner, certain deductions for IDCs, depletion, and depreciation must be recaptured as ordinary income.

A limited partner may be required to recapture as ordinary income certain deductions for IDCs, depletion, and depreciation on disposition of property by the Partnership or on disposition of the Partnership’s common units.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

The U.S. legislature regularly considers budget proposals that may impact many tax incentives and deductions that are currently used by U.S. oil and gas companies. Among others, budget provisions may include: repeal of the deduction of IDC; repeal of the percentage depletion deduction for oil and natural gas properties; repeal of the domestic manufacturing tax deduction for oil and gas companies; and an increase in the amortization period for geological and geophysical costs of independent producers.

The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could increase the amount of the Partnership’s taxable income allocable to a limited partner. The Partnership is unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any modifications to the federal income tax laws or interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in the Partnership’s common units.

Limited partners may be subject to a limit on the ability to deduct interest expense incurred by the Partnership.

In general, the Partnership is entitled to a deduction for interest paid or accrued on indebtedness properly allocable to the Partnership’s trade or business during its taxable year. However, for taxable years beginning after December 31, 2017, the Partnership’s deduction for “business interest” is limited to the sum of the Partnership’s business interest income and 30% of “adjusted taxable income.” For the purposes of this limitation, the Partnership’s adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.

A limited partner maywill likely be subject to state and local taxes and tax return filing requirements in states where they do not live as a result of investing in the Partnership’s common unitsunits.

In addition to federal income taxes, a limited partner will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which the Partnership does business or owns property, even if a limited partner does not live in any of those jurisdictions. A limited partner will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, a limited partner may be subject to penalties for failure to comply with those requirements. It is the responsibility of each limited partner to file its own federal, state and local tax returns, as applicable.

The Partnership may be required to remit federal or state income taxes to applicable taxing authorities on behalf of its limited partners.

The IRS requires that federal income tax be withheld with respect to taxable income allocable to partners who are non-residents of the United States. Similarly, many states require that partnerships make tax payments on behalf of partners who are non-residents of the state. Although many states have exceptions for publicly traded partnerships, the Partnership may not qualify for these exceptions based upon the precise legal definitions involved. If the Partnership is required to remit income tax on behalf of its limited partners, the Partnership Agreement permits such withholdings to be treated as a distribution to the affected partners, since the amounts remitted represent a payment of income tax on behalf of the affected partners.

In mid-2022, the Partnership was contacted by the state of North Dakota, which asserted that the Partnership has an obligation to make tax payments on behalf of certain non-resident partners. Discussions with the state of North Dakota are ongoing, and a resolution may be reached that entails the Partnership making a payment of taxes on behalf of certain limited partners to the state. If a payment of taxes is made on behalf of limited partners, the affected partners should be able to claim the amounts remitted as a tax payment on their originally filed or amended income tax returns to the state of North Dakota, as appropriate.

Item 1B.Unresolved Staff Comments

None

Item 2.Properties

Information regarding the Partnership’s properties is contained in Item 1 – Business, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Item 8 – Financial Statements and Supplementary Data: Note 3. Oil and Gas Investments, appearing elsewhere within this Annual Report on Form 10-K.

Item 3.Legal Proceedings

At the end of the period covered by this Annual Report on Form 10-K, the Partnership was not a party to any material, pending legal proceedings.

Item 4.Mine Safety Disclosures

Not applicable.

Part II

Item 5.Market For Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Common Units

As of December 31, 2021,2022, there were approximately 19.0 million common units outstanding, which were held by approximately 4,800 limited partners. There is currently no established public trading market in which the Partnership’s common units are traded.

Solely to assist trustees and custodians of individual retirement accounts (“IRAs”) containing an investment in the Partnership’s common units and to assist broker-dealers in meeting their customer account statement reporting obligations under Financial Industry Regulatory Authority (“FINRA”) rules for investments in the Partnership, the Partnership announcedis providing an estimated per common unit value of the Partnership’s common units as of December 31, 20212022 of $22.19$23.07 per common unit, as further described below. There can be no assurance that this estimated value per common unit, or the method used to estimate such value, complies with requirements applicable to a trustee’s, custodian’s or broker-dealer’s obligations with respect to IRAs or FINRA’s reporting requirements.

The fair value estimate of the Partnership’s common units was based upon a third-party valuation, performed by Pinnacle Energy Services of Oklahoma City, Oklahoma, of the Partnership’s oil and natural gas properties and management’s estimate of the fair value of the Partnership’s other assets and liabilities as of December 31, 2021.2022. The developed per common unit value range is $20.18$22.55 – $24.57.$24.15. The Partnership utilized the mid-point of the assumptions discussed below to determine the estimated value per common unit above. The following is a summary of the details of the fair value estimate:

Since the Partnership’s common units are not listed on a national securities exchange, no material public market exists for the Partnership’s common units. As a result, although not prepared for generally accepted accounting purposes, the value estimate of the Partnership’s oil and gas properties was derived from unobservable inputs and was based on the income approach as outlined in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures. In the income approach, the estimated value of the Partnership’s oil and gas properties was calculated from a discounted cash flow model using consolidated projected cash flows of the Partnership’s reserves, as well as a discount rate based on market conditions at December 31, 2021.2022. An additional market-based adjustment was made to reflect the probability of successful future development of the Partnership’s oil and gas reserves at December 31, 2021.2022. The Partnership’s cash and cash equivalents are all highly liquid with maturities of three months or less and the fair market value approximates the carrying value. The Partnership’s other assets and liabilities include receivables from the sale of oil, natural gas and natural gas liquids, accounts payable and accrued expenses, which are short-term in nature, and the carrying value of these assets and liabilities approximates fair value at December 31, 2021.2022. The carrying value of the Partnership’s outstanding debt was considered to approximate fair value at December 31, 20212022 based on general market conditions and its maturity. The preferred distribution rights represent the Incentive Distribution Rights, the Class B units and a contingent incentive fee due to the Dealer Manager, as defined in the Partnership’s prospectus, which receive a percentage of the excess if any of the proceeds received by the common units from the Partnership’s assets and liabilities exceed $20.00 per common unit (“Payout”). The valuation methodology and calculations were reviewed by management of the Partnership and considered reasonable. The estimated value was not based on an appraisal of the Partnership’s assets.

As with any methodology used to estimate value, the methodology employed by the Partnership was based upon a number of estimates and assumptions that may not be accurate or complete and may not accurately reflect future conditions. The estimates and assumptions underlying the estimated value involve judgments with respect to, among other things, future economic, competitive, regulatory and financial market conditions and future business decisions which may not be realized and that are inherently subject to significant business, economic, competitive and regulatory uncertainties and contingencies, including, among others, risks and uncertainties described in the periodic reports filed by the Partnership with the Securities and Exchange Commission (“SEC”), all of which are difficult to predict and many of which are beyond the control of the Partnership. Further, different parties using different assumptions and estimates could derive a different estimated value per common unit, which could be significantly different from the Partnership’s estimated value per common unit.

The estimated per common unit value does not represent: (i) the amount at which the Partnership’s common units would trade on a national securities exchange, (ii) the amount a limited partner would obtain if he or she tried to sell his or her common units or (iii) the amount limited partners would receive if the Partnership liquidated its assets and distributed the proceeds after paying all expenses and liabilities. Accordingly, with respect to the estimated value per common unit, the Partnership can give no assurance that:

The estimated value reflects the fact that the estimate was calculated as of a point in time. The value of the Partnership’s common units will likely change over time and will be influenced by changes to the value of individual assets, changes in the oil and gas industry, as well as changes and developments in the energy and capital markets. The Partnership does not intend to update or otherwise revise the above information to reflect circumstances existing after the date when made or to reflect the occurrence of future events, even in the event that any or all of the assumptions underlying the information are no longer appropriate.

As discussed above, the estimated value of the Partnership’s oil and gas properties was determined based on various market level assumptions, including but not limited to commodity market prices, discount rates and processing and transportation costs. The following is a list of key assumptions used in the calculation of the estimated value of the Partnership’s oil and gas properties, a component of the estimated value per common unit:

A change in any of the assumptions would likely produce a different estimated value per common unit. For example:

Class B Units

As of December 31, 20212022 and 2020,2021, the outstanding Class B units totaled 62,500. The Partnership may issue up to 37,500 additional Class B units. The Class B units provide for certain distribution rights described below.

Incentive Distribution Rights and Contingent Incentive Fee

The General Partner received the Incentive Distribution Rights upon closing of the minimum offering in August 2015. Under the agreement with the Dealer Manager, the Dealer Manager will be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold in the Partnership’s offering, the total contingent fee is approximately $15.0 million. The Partnership will not make any distributions with respect to the Incentive Distribution Rights or the contingent, incentive payments to the Dealer Manager, until Payout occurs, as described below.

Distribution Policy

Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights or with respect to Class B units and will not make the contingent, incentive payments to the Dealer Manager, until Payout occurs.

The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to market volatility caused by the onset of the COVID-19 pandemic and the impact on the Partnership’s operating cash flows. Further, the Partnership was restricted in making distributions to limited partners under its credit agreements with Simmons Bank (paid off in full in May 2021) and BancFirst (entered in May 2021) until certain conditions within those credit agreements had been met. In November 2021, theThe Partnership successfully met the required conditions under its BancFirst credit agreement to resume distributions to limited partners. Subsequently, the General Partner approved a partial distributionpartners in November 2021 and a full distribution in2021. For the year ended December 2021.31, 2022, the Partnership paid distributions of $1.258082 per common unit, or $23.9 million. For the year ended December 31, 2021, the Partnership declared and paid distributions of $0.189863 per common unit, or $3.6 million. For the year ended December 31, 2020, the Partnership paid distributions of $0.241644 per common unit, or $4.6 million.

The Partnership accumulates unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs, as defined above. As of December 31, 2021,2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.

Neither the Partnership nor the General Partner has adopted an equity compensation plan.

Item 6.Selected Financial Data [Reserved]

Not applicable.

Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with Item 8 – the Consolidated Financial Statements and Notes thereto, the introduction of Part I regarding “Forward-Looking Statements,” and Item 1A – Risk Factors appearing elsewhere in this Annual Report on Form 10-K.

Overview

Energy 11, L.P. (the “Partnership”) was formed as a Delaware limited partnership. The General Partner is Energy 11 GP, LLC (the “General Partner”). The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership began offering common units of limited partner interest (the “common units”) on a best-efforts basis on January 22, 2015, the date the Partnership’s initial Registration Statement on Form S-1 (File No. 333-197476) was declared effective by the SEC. The Partnership completed its best-efforts offering on April 24, 2017. Total common units sold were approximately 19.0 million for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.

The Partnership has no officers, directors or employees. Instead, the General Partner manages the day-to-day affairs of the Partnership, and all decisions regarding the management of the Partnership are made by the Board of Directors of the General Partner and its officers.

The Partnership was formed to acquire and develop oil and natural gas properties located onshore in the United States. On December 18, 2015, the Partnership completed its first purchase in the Sanish field, acquiring an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. On January 11, 2017, the Partnership closed on its second purchase in the Sanish field, acquiring an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. On March 31, 2017, the Partnership closed on its third purchase in the Sanish field, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s then 216 existing producing wells and 150 of the Partnership’s then 253 future development locations in the Sanish Field Assets for approximately $52.4 million.

Since the beginning of 2018, the Partnership has elected to participate in the drilling and completion of 6786 new wells in the Sanish field. Fifty-one (51)field, of these 67which 80 of those 86 wells have been completed and were producing at December 31, 2021.2022. The Partnership has six wells that are in-process as of December 31, 2021 and expects ten2022; the six wells are anticipated to commence drillingbe completed in the first quarter of 2022.2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 6786 wells is approximately $89$119 million, of which approximately $70$116 million had been incurred as of December 31, 2021.2022. See additional detail in “Oil and Natural Gas Properties” below.

As a result of these acquisitions and completed drilling during the period of ownership, as of December 31, 2021,2022, the Partnership owns an approximate 25%24% non-operated working interest in 266293 producing wells, an estimated approximate 23%12% non-operated working interest in 6 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Chord Energy Corporation (“Chord”, NASDAQ: CHRD), the product of a merger between Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL)and Oasis Petroleum Inc., is one of the largest producers in the basin and operates substantially all of the Sanish Field Assets.

Current Price Environment

Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control. Historically, world-wide oil and natural gas prices and markets have been subject to significant change and may continue to be in the future. Global macroeconomic factors contributing to uncertainty within the industry include real or perceived geopolitical risks in oil-producing regions of the world, particularly Russia and the Middle East; forecasted levels of global economic growth combined with forecasted global supply; supply levels of oil and natural gas due to exploration and development activities in the United States; environmental and climate change regulation; actions taken by the Organization of the Petroleum Exporting Countries (“OPEC”); and the strength of the U.S. dollar in international currency markets.

The outbreak of a novel coronavirus (“COVID-19”) in China in December 2019 significantly impactedCommodity prices strengthened throughout 2021, primarily driven by increased demand resulting from the global economy throughout 2020.initial recovery from the COVID-19 rapidly spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries, creating extreme volatility in capital markets and the global economy. On March 11, 2020, the World Health Organization declared COVID-19 a pandemic and on March 13, 2020, the United States declared a national emergency with respect to COVID-19. In addition to the outbreak of COVID-19, Saudi Arabia and Russia, two of the largest worldwide producers of crude oil, engaged in a price war during March and April 2020 that ultimately led to excess crude oil and natural gas inventory and congested supply chain channels, which weighed negatively on commodity prices while demand was low.

COVID-19’s impact to the global economy significantly decreased demand for oil, natural gas and NGL for the majority of 2020, but demand began to return in the fourth quarter of 2020 as government-mandated COVID-19 restrictions eased. Productionproduction restraint by domestic and foreign operators in 2021,operators. The ongoing military conflict between Russia and Ukraine and related economic sanctions imposed on Russia along with the increased demand, contributed to higher commodity prices, withadditional production growth by OPEC have further exacerbated supply shortages, causing oil prices averaging approximately $77to peak at over $120 per barrel forduring the fourthsecond quarter of 2021. As noted in the table below, the average2022. Average oil and natural gas market prices for 2022 were approximately 39% and 66% higher than 2021, respectively. Commodity prices did fall through the second half of $68 per barrelthe year, with fourth quarter 2022 averages of $82.64 for oil and $3.89$5.55 per Mcf ofMMBtu for natural gas in 2021 were 74% and 92% higher than 2020 market pricing, respectively.gas.

The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 20212022 and 2020.2021.

As specified by the SEC, the prices for oil, natural gas and NGL used to calculate the Partnership’s reserves are based on the unweighted arithmetic average prices as of the first day of each of the twelve months during the years ended December 31, 20212022 and 2020.2021. The average realized oil, natural gas and NGL prices, including the effect of price differential adjustments, used in computing the Partnership’s reserves as of December 31, 2022 were $90.51 per barrel of oil, $6.75 per MMcf of natural gas and $40.28 per barrel of NGL. The average realized oil, natural gas and NGL prices, including the effect of price differential adjustments, used in computing the Partnership’s reserves as of December 31, 2021 were $60.08 per barrel of oil, $3.72 per MMcf of natural gas and $26.62 per barrel of NGL. The average realized oil, natural gas and NGL prices, including the effect of price differential adjustments, used in computing the Partnership’s reserves as of December 31, 2020 were $32.08 per barrel of oil, $(0.55) per MMcf of natural gas and $5.54 per barrel of NGL. See “Note 10 — Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)” in Part II, Item 8. Financial Statements and Supplementary Data” of this Form 10-K for more information on the oil, natural gas and NGL prices used in computing the Partnership’s reserves as of December 31, 20212022 and 2020.2021.

Results of Operations for Years 20212022 and 20202021

In evaluating financial condition and operating performance, the most important indicators on which the Partnership focuses are (1) total quarterly sold production in barrel of oil equivalent (“BOE”) units, (2) average sales price per unit for oil, natural gas and natural gas liquids, (3) production costs per BOE and (4) capital expenditures.

The following is a summary of the results from operations, including production, of the Partnership’s non-operated working interest for the years ended December 31, 20212022 and 2020. The effect of the outbreak of COVID-19 during the first and second quarters of 2020 had a significant negative impact to the Partnership’s results from operations; as a result, the periods presented in the table below may not be directly comparable.2021.

Oil, natural gas and NGL revenues

For the years ended December 31, 20212022 and 2020,2021, revenues for oil, natural gas and NGL sales were $74.1$112.0 million and $36.5$74.1 million, respectively. Revenues for the sale of oil were $61.4$94.8 million and $31.7$61.4 million, which resulted in realized prices of $63.49$89.85 and $31.22$63.49 per barrel, respectively. Revenues for the sale of natural gas were $5.5$8.6 million and $2.1$5.5 million, which resulted in realized prices of $4.75$6.49 and $2.01$4.75 per Mcf, respectively. Revenues for the sale of NGL were $7.2$8.6 million and $2.7$7.2 million, which resulted in realized prices of $43.62$45.41 and $17.14$43.62 per barrel of oil equivalent (“BOE”) of production, respectively. Average realized prices in the fourth quarter of 2022 were approximately $80.50 per barrel of oil, $4.90 per Mcf of natural gas and $33.75 per BOE of NGL, compared to fourth quarter of 2021 wererealized prices of approximately $72.73 per barrel of oil, $5.62 per Mcf of natural gas and $54.23 per BOE of NGL, compared to fourth quarter of 2020 realized prices of approximately $36.41 per barrel of oil, $2.34 per Mcf of natural gas and $22.27 per BOE of NGL.

The Partnership’s results for the year ended December 31, 20212022 were positively impacted by the significant increase in market prices of oil and natural gas and NGLs when compared to the year ended December 31, 2020.2021. In addition, the Partnership realized sales prices for natural gas and NGLs exceeded average market prices throughout 2021, and specifically in February 2021 as a resultcontinues to benefit from the easing of the severe winter weather storms that resulted in power outages in Texas and other southern states. The Partnership’s realized sales prices for oil and natural gas have also benefited from improved differentials (see below) during 2021 as the market imbalances and certain supply chain constraints that developed during the spring and summer of 2020 due to COVID-19, have eased.realized through reduced differentials (see below). The Partnership’s realized sales prices for NGLs are influenced by the components extracted, including ethane, propane and butane and natural gasoline, among others, and the respective market pricing for each component.

The Partnership has completed 2274 new wells fromsince the fourth quarter of 2019, through the third quarter of 2020. In addition, the Partnership’s operatorswhich 52 were completed and turned an additional 23 new wells to sales fromduring the second quarter toof 2021 through December 31, 2022. Sold production volumes increased when comparing the fourth quarter of 2021. The timing of when these wells were completed has positively contributed to sold oil production during thethree-month periods and years ended December 31, 2022 and 2021, and 2020, as newproduction from newly-completed wells often have high levels of production immediately following completion, then decline to more consistent levels. Further, the Partnership’s operators have improved the treatment and processing of extracted natural gas from the Sanish Field Assets, ultimately reducinghas exceeded the natural gas shrinkproduction declines as wells age. The Partnership experienced an immediate boost in production during the third and yielding higher gas and NGL volumes during 2021,fourth quarters of 2022 in comparison to 2020.conjunction with the recent completion of 28 wells. Sold production for the Sanish Field Assets was approximately 4,700 BOE per day for the fourth quarter of 2022, compared to 4,300 BOE per day for the fourth quarter of 2021 and approximately 3,600 BOE per day for the year ended December 31, 2021. Sold production for the Sanish Field Assets was approximately 3,8004,000 BOE and 3,600 BOE per day for the fourth quarter of 2020 and approximately 3,700 BOE per day for the yearyears ended December 31, 2020. The completion of the 16 wells in which the Partnership has recently elected to participate, of which six are already in progress, is anticipated to further contribute to an increase in daily production of the Sanish Field Assets into the first half of 2022.2022 and 2021, respectively.

If commodity prices fall from current levels and operators are unable to produce, process and sell oil and natural gas at economical prices, the operators in the Sanish field may curtail daily production, shut-in producing wells or seek other cost-cutting measures, and could continue so long as producing is uneconomical. Consequently, any of these measures could significantly impact the Partnership’s oil, natural gas and NGL production. Further, production is dependent on the investment in existing wells and the development of new wells. See further discussion of the Partnership’s investment in new wells in “Liquidity and Capital Resources” below.

Oil differentials

The realized prices per barrel of oil above are based upon the NYMEX benchmark price less a cost to distribute the oil, or the differential. Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation methods out of the Sanish field. Oil price differentials to the NYMEX benchmark price vary by operator based upon operator-specific contracts. Due to improvement in commodity prices and market-specific conditions in the Bakken, oil price differentials were nearly 30%approximately 63% less per barrel during 20212022 than 2020.2021.

In July 2020, the U.S. District Court for D.C. (“D.C. District Court”) ruled that the Dakota Access Pipeline, a significant pipeline that transports oil and natural gas from North Dakota fields, must suspend operations due to inadequate environmental review previously performed by the U.S. Army Corps of Engineers. In August 2020, the ruling was stayed on appeal by the U.S. Court of Appeals for the D.C. Circuit (“D.C. Appellate Court”), allowing the pipeline to operate until a further ruling was made. In January 2021, the D.C. Appellate Court affirmed the D.C. District Court’s decision. Further, in May 2021, the D.C. District Court denied an injunction that would have required a shutdown of the Dakota Access Pipeline while the U.S. Army Corps of Engineers completes its comprehensive environmental review. In June 2021, the D.C. District Court dismissed the existing claims against the Dakota Access Pipeline and its operators, but stated the plaintiffs could renew challenges against the pipeline after the U.S. Army Corps of Engineers releases its environmental review report. In February 2022, the United States Supreme Court declined to take a case brought by the Dakota Access Pipeline operators that challenged the requirement of an updated environmental review as upheld by lower courts. The U.S. Army Corps of Engineers report which is anticipatedhas yet to be issued in the fall of 2022.issued. If use of the Dakota Access Pipeline or any other region pipelines is suspended at a future date, the disruption of transporting the Partnership’s production out of North Dakota could negatively impact the Partnership’s realized sales prices, results of operations or cash flows.

Operating costs and expenses

Production expenses

Production expenses are daily costs incurred by the Partnership to bring oil and natural gas out of the ground and to market, along with the daily costs incurred to maintain producing properties. Such costs include field personnel compensation, saltwater disposal, utilities, maintenance, repairs and servicing expenses related to the Partnership’s oil and natural gas properties, along with the gathering and processing contract in effect for the extraction, transportation and treatment of natural gas.

For the years ended December 31, 20212022 and 2020,2021, production expenses were $11.6$17.7 million and $9.8$11.6 million, respectively, and production expenses per BOE of sold production were $12.07 and $8.77, respectively. Production expenses for the fourth quarters of 2022 and $7.29,2021 were $4.9 million and $3.3 million, respectively, and production expenses per BOE of sold production were $11.28 and $8.48, respectively. Production expenses per BOE increased in the quarter and year ended December 31, 2021,2022, in comparison to 2020,same periods of 2021, as a result of (i) a rise in lease operating costs due to inflation; (ii) an increase in workover expenses as certain of the Partnership’s existing producing wells that had been temporarily suspended for the development of new wellshave required additional maintenance and/or rework prior to being returnedeither maintain production efficiency or return to full production; (ii) the Partnership realizing a reduction in lease operating expenses during 2020 as operators implemented cost-saving measures to save on routine costs while market conditions were depressed during 2020;production, and (iii) an increase in total gathering, processing and selling costs associated with the increased sale of the Partnership’s natural gas and NGL production. The production costs specific to the processing, treating and marketing of natural gas and NGLs are higher than those associated with oil, so an increase in sold natural gas and NGLs (in proportion to total sold volumes) results in a greater increase in these production expenses per BOE than the corresponding increase in production expenses for new oil production.

Production expenses for the fourth quarters of 2021 and 2020 were $3.3 million and $2.8 million, respectively, and production expenses per BOE of sold production were $8.48 and $8.07, respectively.

Production taxes

Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. Taxes on the sale of gas and NGL products are less than taxes levied on the sale of oil. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGLs to total sales. Production taxes for the years ended December 31, 2022 and 2021 and 2020 were $5.7$9.1 million (8% of revenue) and $3.1$5.7 million (8% of revenue), respectively. Production taxes for the fourth quarters of 2022 and 2021 and 2020 were $2.0$2.7 million (8%(9% of revenue) and $0.9$2.0 million (8% of revenue), respectively. Oil production has comprised approximately 72% and 73% of the Partnership’s sold production volumes in bothfor the three months and years ended December 31, 2022 and 2021, and 2020.73% in both three-month periods ended December 31, 2022 and 2021.

General and administrative expenses

General and administrative costs for the years ended December 31, 2022 and 2021 and 2020 were $1.5$2.1 million and $1.6$1.5 million, respectively. The principal components of general and administrative expense are accounting, legal and consulting fees. The Partnership incurred higher legal fees to protect its rights under joint operating agreements with its operators during the year ended December 31, 2020.2022.

Depreciation, depletion, amortization and accretion (“DD&A”)

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. DD&A for the years ended December 31, 2022 and 2021 and 2020 was $22.5$21.0 million and $22.7$22.5 million, and DD&A per BOE of sold production was $16.96$14.30 and $16.79,$16.96, respectively. DD&A for the fourth quarters of 20212022 and 20202021 was $6.1 million in both periods, and DD&A per BOE of sold production was $15.40$14.17 and $17.26,$15.40, respectively. The decrease in DD&A expense per BOE of production in the fourth quarter of 2021during 2022 is primarily due to the increase of the Partnership’s estimated proved undeveloped reserves as of December 31, 20212022 resulting from changes in the future drill schedule.

Loss on derivatives, net

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Periodically, the Partnership utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations.

In accordance with the amended Simmons Loan Agreement discussed in “Financing” below,Partnership’s previous credit facility, the Partnership was required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 2020 through February 2021. In July 2021, the Partnership began its risk management program required under the BFBancFirst Loan Agreement (see “Financing” below) by entering into costless collar derivative contracts for the period from July 2021 to September 2023.

The Partnership did not designate its 20202021 or 20212022 derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents settlements of its matured derivative instruments and the non-cash, mark-to-market gains or losses recorded during the periods presented.

The Partnership’s oil production contracts that expired during 2022 represented 322,000 barrels of oil. The Partnership’s realized loss on its oil contracts of approximately $6.1 million equated to an approximate loss of $18.28 per barrel of oil. The Partnership’s natural gas production contracts that expired during 2022 represented 380,000 MMBtu of produced natural gas. The Partnership’s realized loss on natural gas contracts of approximately $0.5 million equated to an approximate loss of $1.41 per MMBtu of natural gas. The Partnership’s oil and natural gas production contracts that expired during the fourth quarter of 2022, which represented 78,000 barrels of oil and 90,000 MMBtu of produced natural gas, resulted in losses of approximately $10.65 per barrel of oil, or $0.8 million, and $1.47 per MMBtu of natural gas, or $0.1 million, respectively.

The Partnership’s oil production contracts that expired during 2021 represented 297,000 barrels of oil. The Partnership’s realized loss of approximately $1.2 million equated to an approximate loss of $3.98 per barrel of oil. The Partnership’s natural gas production contracts that expired during 2021 represented 360,000 MMBtu of produced natural gas; however, these natural gas production contracts were settled at no cost or benefit to the Partnership, as contract prices on settlement dates were within the established floor and ceiling prices. The Partnership’s oil and natural gas production contracts that expired during the fourth quarter of 2021, which represented 93,000 barrels of oil and 120,000 MMBtu of produced natural gas, respectively, were also settled at no cost or benefit to the Partnership.

The Partnership’s oil production contracts that expired during 2020 represented 372,000 barrels of oil. The Partnership’s realized net gain of approximately $107,000 equated to an approximate net gain of $0.29 per barrel of oil. The Partnership’s natural gas production contracts that expired during 2020 represented 330,000 Mcf of produced natural gas, and settlement gains were approximately $40,000, or $0.12 per Mcf.

The mark-to-market (non-cash, unrealized) net losses recorded for the years ended December 31, 20212022 and 20202021 represent the change in fair value of the Partnership’s derivative instruments held at period-end. Unrealized gains and losses do not represent actual settlements or payments made to or from the counterparty.

The table below summarizes the Partnership’s outstanding derivative contracts (costless collars – purchased put options and written call options) on the Partnership’s future oil and natural gas production.

Interest expense, net

Interest expense, net, for the years ended December 31, 2022 and 2021 was $1.5 million and 2020 was $1.8 million, and $1.9 million, respectively. The primary component of Interest expense, net, during the year ended December 31, 2022 was interest expense on the BancFirst Credit Facility (“BF Credit Facility”). The primary component of Interest expense, net, during the year ended December 31, 2021 was interest expense on the BF Credit Facility, the Affiliate Loan and the Simmons Credit Facility (including the write-off of unamortized capitalized loan costs associated with the Simmons Credit Facility), discussed below in “Financing.” The primary component of Interest expense, net, during the year ended December 31, 2020 was interest expense on the Simmons Credit Facility.. The Partnership made approximately $17 million in principal paymentsmaintained a lower outstanding balance on the BF Credit Facility during 2022, which led to reduced interest expense in 2022. However, the second half of 2021,interest rate on the BF Credit Facility increased from 4.0% in January 2022 to 8.0% in December 2022, which contributed to a decrease inwill impact the Partnership’s interest expense in 2021.during 2023.