10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON D.C. 20549

FORM 10-K

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

For the fiscal year ended: December 31, 2022

OR

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

COMMISSION FILE NUMBER: 000-55615

ENERGY 11, L.P.

(Exact name of Registrant as specified in its charter)

Delaware	46-3070515
(State or other jurisdiction of incorporation)	(I.R.S. Employer Identification Number)
120 W 3rd Street, Suite 220
Fort Worth, Texas	76102
(Address of principal executive office)	(Zip Code)

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

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

Title of each class	Trading Symbol	Name of each exchange on which registered
None

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.

Large accelerated filer ☐	Accelerated filer ☐
Non-accelerated filer ☑	Smaller reporting company ☑
Emerging growth company ☐

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, 2022 was $0.

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

ENERGY 11, L.P.

FORM 10-K

Index

		Page
Part I
	Item 1. Business	5
	Item 1A. Risk Factors	21
	Item 1B. Unresolved Staff Comments	36
	Item 2. Properties	36
	Item 3. Legal Proceedings	36
	Item 4. Mine Safety Disclosures	36
Part II
	Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	37
	Item 6. [Reserved]	40
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
	Item 7A. Quantitative and Qualitative Disclosures about Market Risk	51
	Item 8. Financial Statements and Supplementary Data	52
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	72
	Item 9A. Controls and Procedures	72
	Item 9B. Other Information	72
	Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	72
Part III
	Item 10. Directors, Executive Officers and Corporate Governance	73
	Item 11. Executive Compensation	75
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	76
	Item 13. Certain Relationships and Related Transactions, and Director Independence	77
	Item 14. Principal Accounting Fees and Services	78
Part IV
	Item 15. Exhibits, Financial Statement Schedules	80
	Item 16. Form 10-K Summary	81
Signatures		82

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:

• the impact of and ongoing recovery from COVID-19;

• references to future success in the Partnership’s drilling and marketing activities;

• the Partnership’s business strategy;

• estimated future capital expenditures;

• estimated future distributions;

• sales of the Partnership’s properties and other liquidity events;

• competitive strengths and goals; and

• other similar matters.

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:

• that the Partnership’s development of its oil and natural gas properties may not be successful or that the Partnership’s operations on such properties may not be successful;

• general economic, market, or business conditions;

• changes in laws or regulations;

• the risk that the wells in which the Partnership acquired an interest are productive, but do not produce enough revenue to return the investment made;

• the risk that the wells the Partnership drills do not find hydrocarbons in commercial quantities or, even if commercial quantities are encountered, that actual production is lower than expected on the productive life of wells is shorter than expected;

• current credit market conditions and the Partnership’s ability to obtain long-term financing for its property drilling activities in a timely manner and on terms that are consistent with what the Partnership projects when it invests in a property;

• uncertainties concerning the price of oil and natural gas, which may decrease and remain low for prolonged periods; and

• the risk that any hedging policy the Partnership employs to reduce the effects of changes in the prices of its production will not be effective.

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.

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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, 2022, the Partnership owns an approximate 24% non-operated working interest in 293 producing wells, an estimated approximate 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 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, 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 86 new wells in the Sanish field, of which 80 of these 86 wells have been completed and were producing at December 31, 2022. The Partnership has six wells that are in-process as of December 31, 2022, which are anticipated to be completed in the first half of 2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells is approximately $119 million, of which approximately $116 million had been incurred as of December 31, 2022.

Industry Operating Environment

The oil and natural gas industry is affected by many 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 the Middle 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 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.

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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.

	Year Ended December 31,				Percent
	2022		2021		Change
Sold production (BOE):
Oil		1,054,619		967,069		9.1	%
Natural gas		221,666		193,321		14.7	%
Natural gas liquids		190,503		164,851		15.6	%
Total		1,466,788		1,325,241		10.7	%
Average sales price per unit:
Oil (per Bbl)	$	89.85	$	63.49		41.5	%
Natural gas (per Mcf)		6.49		4.75		36.6	%
Natural gas liquids (per Bbl)		45.41		43.62		4.1	%
Combined (per BOE)		76.38		55.91		36.6	%
Average unit cost per BOE:
Production costs
Production expenses		12.07		8.77		37.6	%
Production taxes		6.21		4.30		44.4	%
Total production costs		18.28		13.07		39.9	%
Depreciation, depletion, amortization and accretion		14.30		16.96		-15.7	%

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.

6

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:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).

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. The Partnership successfully met the required conditions under its BancFirst credit agreement to resume distributions to limited partners in November 2021. For the year ended December 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.

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, 2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.

7

Oil and Natural Gas Reserves

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

	Number of wells		Oil (MBbls)		Natural Gas (MMcf)		NGL (MBbls)		Total (MBOE)		Standardized Measure (2)
											(in thousands)
Proved Reserves (1)
PDP Properties		254		11,824		14,612		2,080		16,340	$	421,322
PDNP Properties		39		1,136		1,935		275		1,734		34,550
PUD Properties		63		8,072		7,930		1,128		10,522		192,338
Total Proved Reserves		356		21,032		24,477		3,483		28,596	$	648,210

(1)

The following terms have been used by the Partnership to classify its reserves: Proved developed producing reserves (“PDP”) are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved developed non-producing reserves (“PDNP”) are proved oil and natural gas reserves that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Proved undeveloped reserves (“PUD”) are reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for development (reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled). The Partnership’s proved reserves as of December 31, 2022 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on unweighted arithmetic average prices as of the first day of each of the twelve months ended on such date. 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. See “Note 10 — Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)” in the accompanying notes to consolidated financial statements included elsewhere in this report for information concerning proved reserves.

(2)

The standardized measure of discounted future net cash flows represents the estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation, in accordance with Accounting Standards Codification Topic 932 – Extractive Activities – Oil and Gas. Because the Partnership was formed as a limited partnership, the Partnership is not subject to federal taxes in the calculation of the standardized measure. In addition, there are no entity level or gross receipts taxes in North Dakota, where all Partnership wells are located, that would give rise to an additional state tax provision.

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, 2022 were below the 2022 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.

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Proved Undeveloped Reserves (PUD)

At December 31, 2022, the Partnership had PUDs of approximately 10,522 MBOE, or approximately 37% of total proved reserves. Total PUDs at December 31, 2021 were 6,627 MBOE. The following table reflects the changes in PUDs during 2022:

	BOE
Proved undeveloped reserves, December 31, 2021		6,627,133
Revisions of previous estimates (1)		7,803,541
Extensions, discoveries and other additions (2)		1,614,430
Conversion to proved developed reserves (3)		(5,523,017	)
Proved undeveloped reserves, December 31, 2022		10,522,087

(1)	The annual review of the PUDs resulted in a positive revision of approximately 7,804 MBOE. This revision was the result of 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and offset by 373 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2022 to December 31, 2021.
(2)	In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(3)	The Partnership completed 27 new wells during 2022; therefore, the Partnership converted these 27 wells to proved developed reserves during 2022, which resulted in a downward adjustment to PUDs of 5,523 MBOE.

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, 2022 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, 2022 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.

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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:

● no employee’s compensation is tied to the amount of reserves booked;

● the Partnership follows comprehensive SEC-compliant internal policies to determine and report proved reserves;

● reserve estimates are made by experienced reservoir engineers or under their direct supervision;

● annual review by the Board of Directors of the General Partner of the Partnership’s year-end reserve estimates prepared by Pinnacle Energy; and

● semi-annually, the Board of Directors of the General Partner reviews all significant reserves changes and all new proved undeveloped reserves additions.

Total Productive Wells

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

	December 31, 2022
	Gross		Net
Oil wells:
Sanish Field		296		72.0

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, 2022, the Partnership had 293 currently producing wells and three shut-in 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, 2022, all of which is located in the State of North Dakota in the United States:

Acreage allocated to developed properties

Acreage allocated to undeveloped wellsites

Total Acres

Gross

Net

Gross

Net

Gross

Net

Sanish Field, Mountrail County, ND

20,347

6,303

14,931

4,625

35,278

10,928

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.

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Undeveloped Acreage Expirations

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

Delivery Commitments

As of December 31, 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.

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

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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:

● require the acquisition of various permits before drilling commences;

● require the installation of pollution control equipment in connection with operations;

● place restrictions or regulations upon the use or disposal of the material utilized in the Partnership’s operations;

● restrict the types, quantities and concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

● limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

● require remedial measures to mitigate or remediate pollution from former and ongoing operations, and may also require site restoration, pit closure and plugging of abandoned wells; and

● require the expenditure of significant amounts in connection with worker health and safety.

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.

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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.

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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 finalized in December 2022 a rule that in practice restores the old 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.

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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 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 had 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 November 2022 rule 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 rules proposed in November 2021 and 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. BLM’s rule was challenged and struck down in federal court in 2020. In November 2022, the BLM proposed a new rule that limits monthly royalty-free natural gas flaring at wells on federal and tribal lands and strengthens requirements to mitigate waste from these wells, including through the implementation of a leak detection and repair program.

In November 2021, the Department of Transportation finalized 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.

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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 April 2022, the Biden administration finalized a rule that reverses most of the rollbacks introduced through the Trump-era regulations. The new revisions represent the first of two phases of NEPA 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 June 2022, in a case called West Virginia v. U.S. Environmental Protection Agency, the United States Supreme Court held that the “major questions” doctrine limits EPA’s power to curtail GHG emissions by requiring power plants to shift generation to lower emitted fuel sources. The case involved 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.

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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 June 2021, the Fish and Wildlife Service under the Biden administration stated its plan to rescind or revise most of the 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 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:

● the location of wells;

● the method of drilling, completing and operating wells;

● the surface use and restoration of properties upon which wells are drilled;

● the plugging and abandoning of wells;

● the marketing, transportation and reporting of production;

● notice to surface owners and other third parties; and

● produced water and waste disposal.

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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.

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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.

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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.

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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:

● the domestic and foreign supply of and demand for oil, natural gas and other hydrocarbons;

● regulations which may prevent or limit the export of oil, natural gas and other hydrocarbons;

● the amount of added production from development of unconventional natural gas reserves;

● the price and quantity of foreign imports of oil, natural gas and other hydrocarbons;

● the level of consumer product demand;

● adverse weather conditions, natural disasters and global health concerns, such as the COVID-19 coronavirus outbreak in early 2020;

● the value of the U.S. dollar relative to the currencies of other countries;

● overall domestic and global economic conditions;

● political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America, China and Russia, and acts of terrorism or sabotage;

● the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

● technological advances affecting energy production and consumption;

● domestic and foreign governmental regulations and taxation;

● the impact of energy conservation efforts;

● the proximity and capacity of oil, natural gas and other hydrocarbon pipelines and other transportation facilities to its production;

● speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;

● price and availability of competitors’ supplies of oil and natural gas; and

● the price and availability of alternative fuels.

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:

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● the amount of oil, natural gas and natural gas liquids the Partnership produces;

● the prices at which the Partnership sells its production;

● the Partnership’s ability to hedge commodity prices at economically attractive prices;

● the level of the Partnership’s capital expenditures, including its costs to participate in wells;

● the level of the Partnership’s operating and administrative costs including reimbursement to the General Partner; and

● the level of the Partnership’s interest expense, which depends on the amount of its indebtedness and the interest payable thereon.

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:

● contractual restrictions on the payment of distributions contained in the Partnership’s credit facility agreement;

● the amount of cash reserves established by the General Partner for the proper conduct of the Partnership’s business and for capital expenditures, which may be substantial;

● the cost of operations, infrastructure and drilling;

● the Partnership’s debt service requirements and other liabilities;

● fluctuations in the Partnership’s working capital needs;

● the Partnership’s ability to borrow funds;

● the timing and collectability of receivables; and

● prevailing economic conditions.

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, 2022, Chord operates 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 Chord, or the Partnership’s other 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 Chord 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.

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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 has yet to be 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 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.

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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:

● incorrect assumptions regarding the future prices of oil, natural gas and other hydrocarbons or the future operating or development costs of properties;

● incorrect estimates of the reserves and projected development results attributable to a property the Partnership owns;

● drilling, operating and other cost overruns;

● an inability to integrate successfully the properties the Partnership has acquired;

● the assumption of liabilities;

● the diversion of management’s attention from other business concerns; and

● losses of key employees.

The Partnership has experienced higher costs in 2022 due to inflation having widespread effects on the economy. Sustained periods of 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.

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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 engage 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:

● unexpected drilling or operating conditions;

● facility or equipment failure or accidents;

● shortages or delays in the availability of drilling rigs and equipment and in hiring qualified personnel;

● adverse weather conditions;

● shortages of water required for hydraulic fracturing or other operations;

● compliance with environmental and governmental requirements;

● reductions in oil or gas prices;

● proximity to and capacity of transportation and processing facilities;

● title problems;

● encountering abnormal pressures or unusual, unexpected or irregular geological formations;

● pipeline ruptures;

● fires, blowouts, craterings and explosions; and

● uncontrollable flows of oil or natural gas or well fluids.

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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:

● damages to equipment caused by natural disasters such as earthquakes, adverse weather conditions, including tornadoes, hurricanes, drought and flooding;

● unexpected formations and pressures;

● facility or equipment malfunctions;

● pipeline ruptures or spills;

● fires, blowouts, craterings and explosions;

● release of toxic gasses;

● uncontrollable flows of oil or natural gas or well fluids; and

● surface fluid spills, saltwater contamination, and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives.

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.

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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:

● Conflicts caused by the incentive distribution rights held by the General Partner, which may cause it to conduct operations that are riskier to the Partnership, or to sell properties, in order to generate distributions from the incentive distribution rights;

● Conflicts caused by the sale of properties to programs that have or may be formed by the General Partner and its affiliates in the future; and

● Conflicts caused by competition for management time and attention with other oil and gas partnerships and with other business activities in which management of the General Partner are or may be involved.

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.

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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:

● neither the Partnership Agreement nor any other agreement requires affiliates of the General Partner to pursue a business strategy that favors the Partnership or to refer any business opportunity to the Partnership;

● the General Partner determines the amount and timing of its asset purchases and sales, capital expenditures and borrowings, each of which can affect the amount of cash that is distributed to holders of the Partnership’s common units or used to service its debt obligations;

● the General Partner controls the enforcement of obligations owed to the Partnership by the General Partner and its affiliates; and

● the General Partner decides whether to retain separate counsel, accountants or others to perform services for the Partnership.

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:

● compensation and fees paid to the General Partner and its affiliates as described above in “— Amounts paid to the General Partner regardless of success of the Partnership’s activities will reduce the cash available for distribution;”

● repayment of borrowings and regularly scheduled debt service payments;

● drilling and completing new wells;

● cost overruns on drilling, completion or operating activities;

● remedial work to improve a well’s producing capability;

● the acquisition of producing and non-producing oil and gas leasehold interests considered in the best interest of the Partnership by the General Partner;

● uninsured losses from operational risks including liability for environmental damages;

● direct costs and general and administrative expenses of the Partnership;

● reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or

● indemnification of the General Partner and its affiliates by the Partnership for losses or liabilities incurred in connection with the Partnership’s activities.

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.

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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.

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, limited partners may be unable to sell or otherwise transfer common units and limited partners may lose some or all of their investment. The Partnership Agreement does not obligate the General Partner to cause a liquidity event within a 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.

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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:

● the Clean Air Act, or the CAA, and comparable state laws and regulations that impose obligations related to emissions of air pollutants;

● the Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated water;

● the Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from the Partnership’s facilities;

● the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by the Partnership or at locations to which the Partnership has sent waste for disposal;

● the Safe Drinking Water Act and state or local laws and regulations related to underground injection (including hydraulic fracturing);

● the Endangered Species Act and comparable state and local laws and regulations which protect endangered and threatened species and the ecosystems on which they depend;

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● the National Environmental Policy Act and comparable state statutes which ensure that environmental issues are adequately addressed in decisions involving major governmental actions (including the leasing of government land);

● the Oil Pollution Act, or OPA, which subject responsible parties to liability for removal costs and damages arising from an oil spill in waters of the U.S.; and

● emergency planning and community right to know regulations under the Title III of CERCLA and similar state statutes require that the Partnership organizes and/or discloses information about hazardous materials used or produced in its operations.

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.

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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:

● Unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on the Partnership’s ability to compete for oil and gas resources;

● Data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;

● Data corruption or operational disruptions of production-related infrastructure could result in a loss of production, or accidental discharge;

● A cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt the Partnership’s major development projects;

● A cyber-attack on third party gathering, pipeline, or rail transportation systems could delay or prevent the Partnership from transporting and marketing its production, resulting in a loss of revenues;

● A cyber-attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing the Partnership from marketing its production or engaging in hedging activities, resulting in a loss of revenues;

● A cyber-attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for the Partnership’s production, lower natural gas prices, and reduced revenues;

● A cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

● A cyber-attack on the Partnership’s automated and surveillance systems could cause a loss in production and potential environmental hazards;

● A deliberate corruption of the Partnership’s financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and

● A cyber-attack resulting in the loss or disclosure of, or damage to, the Partnership’s or any of its customer’s or supplier’s data or confidential information could harm the Partnership’s business by damaging its reputation, subjecting it to potential financial or legal liability, and requiring it to incur significant costs, including costs to repair or restore its systems and data or to take other remedial steps.

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.

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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 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, 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.

If 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 these 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.

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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.

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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 will 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 units.

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.

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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.

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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, 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 is providing an estimated per common unit value of the Partnership’s common units as of December 31, 2022 of $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, 2022. The developed per common unit value range is $22.55 – $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:

(in thousands, except per common unit data)	Estimate at 12/31/22
	(unaudited)
Estimated fair value of oil and gas properties	$	510,762
Estimated fair value of cash and cash equivalents		3,053
Estimated fair value of other assets and liabilities, net		(1,654	)
Estimated fair value of outstanding debt		(22,600	)
Estimated fair value of preferred distribution rights above Payout		(51,817	)
Estimated fair value of equity	$	437,744
Common units outstanding		18,973
Estimated value per common unit	$	23.07

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, 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, 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, 2022. The carrying value of the Partnership’s outstanding debt was considered to approximate fair value at December 31, 2022 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.

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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:

• a limited partner would be able to resell his or her common units at this estimated value;

• a limited partner would ultimately realize distributions per common unit equal to the estimated value per common unit upon liquidation of the Partnership’s assets and settlement of its liabilities or a sale of the Partnership (in part because estimated values do not necessarily indicate the price at which individual assets or the Partnership could be sold, oil and gas property values fluctuate and change, and the estimated value may not take into account the expenses associated with such a sale);

• the Partnership’s common units would trade at a price equal to or greater than the estimated value per common unit if they were listed on a national securities exchange;

• the methodology used to estimate the value per common unit would be acceptable to FINRA or for compliance with requirements applicable to a trustee’s or custodian’s obligations with respect to IRAs; or

• any or all of the assumptions used in estimating the value per common unit will prove to be accurate or complete.

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:

• NYMEX oil strip pricing as of January 1, 2023, which ranges from $79.47 per barrel to $64.14 per barrel as of January 1, 2023 to December 31, 2027, and an increase of 3% thereafter with price cap at $85.00 per barrel

• NYMEX gas strip pricing as of January 1, 2023, which ranges from $4.24 per Mcf to $4.50 per Mcf as of January 1, 2023 to December 31, 2027, and then held flat thereafter at a price cap of $4.50 per Mcf

• Differentials to NYMEX strip pricing due to product processing, transportation or contract terms

- Weighted average oil differential of -$3.11 per barrel of oil

- Weighted average natural gas differential of +$0.36 per Mcf of natural gas

- Natural gas liquids (NGL) pricing determined using 43.0% of NYMEX oil price

- Weighted average natural gas shrink of 33.0%

- NGL yield of 95.34 barrels per MMcf of wet gas

• Additional gathering and processing (G&P) expenses subsequently applied after differentials to NYMEX strip pricing

- Weighted average G&P expense on the production and sale of oil of $0.53 per barrel

- Weighted average G&P expense on the production and sale of natural gas of $2.75 per Mcf

- Weighted average G&P expense on the production and sale of NGL of $11.50 per barrel of oil equivalent

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• Total gross fixed lease operating expenses per well estimated at $5,500 per month

• Total net variable lease operating and workover expenses per well estimated at $4.10 per barrel of oil

• Gross capital expenditures to drill and complete future development locations estimated at $7.2 million per well

• Discount rate – 10.0%

• Risk adjustments to calculated present value

- Proved developed producing (PDP) assets – 5.0%

- Proved developed non-producing (PDNP) assets – 10.0%

- Proved undeveloped (PUD) assets to be drilled within five years – 15.0%

- Proved undeveloped (PROB) assets to be drilled between five and ten years – 25.0%

- Proved undeveloped (POSS) assets to be drilled after ten years – 35.0%

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

• An increase in the discount rate assumption of 100 basis points would decrease the per common unit value range by approximately $0.52 per common unit, all other assumptions remaining the same;

• A decrease in the discount rate assumption of 100 basis points would increase the per common unit value range by approximately $1.08 per common unit, all other assumptions remaining the same;

• An increase in the average NYMEX oil and natural gas strip pricing assumptions of 500 basis points would increase the per common unit value range by approximately $0.70 per common unit, all other assumptions remaining the same;

• A decrease in the average NYMEX oil and natural gas strip pricing assumptions of 500 basis points would decrease the per common unit value range by approximately $0.46 per common unit, all other assumptions remaining the same;

• An increase of 500 basis points in the risk adjustment percentage to calculated present value per reserve category would decrease the per common unit value range by approximately $0.44 per common unit, all other assumptions remaining the same; and

• A decrease of 500 basis points in the risk adjustment percentage to calculated present value per reserve category would increase the per common unit value range by approximately $0.67 per common unit, all other assumptions remaining the same.

Class B Units

As of December 31, 2022 and 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.

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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:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).

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. The Partnership successfully met the required conditions under its BancFirst credit agreement to resume distributions to limited partners in November 2021. For the year ended December 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.

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, 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. [Reserved]

Not applicable.

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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 86 new wells in the Sanish field, of which 80 of those 86 wells have been completed and were producing at December 31, 2022. The Partnership has six wells that are in-process as of December 31, 2022; the six wells are anticipated to be completed in the first quarter of 2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells is approximately $119 million, of which approximately $116 million had been incurred as of December 31, 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, 2022, the Partnership owns an approximate 24% non-operated working interest in 293 producing wells, an estimated approximate 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 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.

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, causing oil prices to peak at over $120 per barrel during the second quarter of 2022. 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 the year, with fourth quarter 2022 averages of $82.64 for oil and $5.55 per MMBtu for natural gas.

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The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2022 and 2021.

	Year Ended December 31,				Percent
	2022		2021		Change
Average market closing prices (1)
Oil (per Bbl)	$	94.33	$	68.11		38.5	%
Natural gas (per Mcf)	$	6.45	$	3.89		65.8	%

(1) Based on average NYMEX futures closing prices (oil) and NYMEX/Henry Hub spot prices (natural gas)

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, 2022 and 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. 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, 2022 and 2021.

Results of Operations for Years 2022 and 2021

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, 2022 and 2021.

	Year Ended December 31,
	2022		Percent of Revenue			2021		Percent of Revenue			Percent Change
Total revenues	$	112,030,792		100.0	%	$	74,098,163		100.0	%		51.2	%
Production expenses		17,706,793		15.8	%		11,619,322		15.7	%		52.4	%
Production taxes		9,108,473		8.1	%		5,700,579		7.7	%		59.8	%
Depreciation, depletion, amortization and accretion		20,974,139		18.7	%		22,473,437		30.3	%		-6.7	%
General and administrative expenses		2,074,306		1.9	%		1,516,357		2.0	%		36.8	%
Sold production (BOE):
Oil		1,054,619					967,069					9.1	%
Natural gas		221,666					193,321					14.7	%
Natural gas liquids		190,503					164,851					15.6	%
Total		1,466,788					1,325,241					10.7	%
Average sales price per unit:
Oil (per Bbl)	$	89.85				$	63.49					41.5	%
Natural gas (per Mcf)		6.49					4.75					36.6	%
Natural gas liquids (per Bbl)		45.41					43.62					4.1	%
Combined (per BOE)		76.38					55.91					36.6	%
Average unit cost per BOE:
Production expenses		12.07					8.77					37.6	%
Production taxes		6.21					4.30					44.4	%
Depreciation, depletion, amortization and accretion		14.30					16.96					-15.7	%
Capital expenditures	$	49,285,758				$	24,078,339

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Oil, natural gas and NGL revenues

For the years ended December 31, 2022 and 2021, revenues for oil, natural gas and NGL sales were $112.0 million and $74.1 million, respectively. Revenues for the sale of oil were $94.8 million and $61.4 million, which resulted in realized prices of $89.85 and $63.49 per barrel, respectively. Revenues for the sale of natural gas were $8.6 million and $5.5 million, which resulted in realized prices of $6.49 and $4.75 per Mcf, respectively. Revenues for the sale of NGL were $8.6 million and $7.2 million, which resulted in realized prices of $45.41 and $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 realized prices of approximately $72.73 per barrel of oil, $5.62 per Mcf of natural gas and $54.23 per BOE of NGL.

The Partnership’s results for the year ended December 31, 2022 were positively impacted by the significant increase in market prices of oil and natural gas when compared to the year ended December 31, 2021. In addition, the Partnership continues to benefit from the easing of market imbalances and supply chain constraints that developed during the spring and summer of 2020 due to COVID-19, 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 74 new wells since the fourth quarter of 2019, of which 52 were completed and turned to sales during the second quarter of 2021 through December 31, 2022. Sold production volumes increased when comparing the three-month periods and years ended December 31, 2022 and 2021, as production from newly-completed wells has exceeded the natural production declines as wells age. The Partnership experienced an immediate boost in production during the third and fourth quarters of 2022 in 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. Sold production for the Sanish Field Assets was approximately 4,000 BOE and 3,600 BOE per day for the years ended December 31, 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 approximately 63% less per barrel during 2022 than 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 has yet to be 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.

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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, 2022 and 2021, production expenses were $17.7 million and $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 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, 2022, in comparison to 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 wells have required additional maintenance and/or rework to either maintain production efficiency or return to full 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 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 were $9.1 million (8% of revenue) and $5.7 million (8% of revenue), respectively. Production taxes for the fourth quarters of 2022 and 2021 were $2.7 million (9% of revenue) and $2.0 million (8% of revenue), respectively. Oil production comprised approximately 72% and 73% of the Partnership’s sold production volumes for the years ended December 31, 2022 and 2021, and 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 were $2.1 million and $1.5 million, respectively. The principal components of general and administrative expense are accounting, legal and consulting fees. The Partnership incurred higher legal fees during the year ended December 31, 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 was $21.0 million and $22.5 million, and DD&A per BOE of sold production was $14.30 and $16.96, respectively. DD&A for the fourth quarters of 2022 and 2021 was $6.1 million in both periods, and DD&A per BOE of sold production was $14.17 and $15.40, respectively. The decrease in DD&A expense per BOE of production during 2022 is primarily due to the increase of the Partnership’s estimated proved undeveloped reserves as of December 31, 2022 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.

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In accordance with the 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 BancFirst 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 2021 or 2022 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.

	Year Ended December 31, 2022			Year Ended December 31, 2021
Settlements on matured derivatives	$	(6,603,660	)	$	(1,182,420	)
Loss on mark-to-market of derivatives, net		(668,714	)		(1,761,563	)
Loss on derivatives	$	(7,272,374	)	$	(2,943,983	)

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 mark-to-market (non-cash, unrealized) net losses recorded for the years ended December 31, 2022 and 2021 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.

Settlement Period	Basis	Product	Volume	Weighted Average Floor / Ceiling Prices ($)
01/2023 - 09/2023	NYMEX	Oil (bbls)	224,000	50.00 / 69.72
02/2023 - 09/2023	Henry Hub	Gas (MMbtu)	275,000	2.00 / 4.30

Interest expense, net

Interest expense, net, for the years ended December 31, 2022 and 2021 was $1.5 million and $1.8 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). The Partnership maintained a lower outstanding balance on the BF Credit Facility during 2022, which led to reduced interest expense in 2022. However, the interest rate on the BF Credit Facility increased from 4.0% in January 2022 to 8.0% in December 2022, which will impact the Partnership’s interest expense during 2023.

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See more information on the Partnership’s credit facilities in “Note 4 – Debt” in Part II, Item 8 – Financial Statements and Supplementary Data appearing elsewhere in this Annual Report on Form 10-K.

Supplemental Non-GAAP Measure

The Partnership uses “Adjusted EBITDAX”, defined as earnings (loss) before (i) interest expense, net; (ii) income taxes; (iii) depreciation, depletion, amortization and accretion, (iv) exploration expenses; and (v) (gain)/loss on the mark-to-market of derivative instruments, as a key supplemental measure of its operating performance. This non-GAAP financial measure should be considered along with, but not as alternatives to, net income, operating income, cash flow from operating activities or other measures of financial performance presented in accordance with GAAP. Adjusted EBITDAX is not necessarily indicative of funds available to fund the Company’s cash needs, including its ability to make cash distributions. Although Adjusted EBITDAX, as calculated by the Partnership, may not be comparable to Adjusted EBITDAX as reported by other companies that do not define such terms exactly as the Partnership defines such terms, the Partnership believes this supplemental measure is useful to investors when comparing the Partnership’s results between periods and with other energy companies.

The Partnership believes that the presentation of Adjusted EBITDAX is important to provide investors with additional information (i) to provide an important supplemental indicator of the operational performance of the Partnership’s business without regard to financing methods and capital structure, and (ii) to measure the operational performance of the Partnership’s operators.

The following table reconciles the Partnership’s GAAP net income (loss) to Adjusted EBITDAX for the years ended December 31, 2022 and 2021.

	Year Ended December 31, 2022		Year Ended December 31, 2021
Net income	$	53,438,007	$	28,049,650
Interest expense, net		1,456,700		1,794,835
Depreciation, depletion, amortization and accretion		20,974,139		22,473,437
Exploration expenses		-		-
Non-cash loss on mark-to-market of derivatives		668,714		1,761,563
Adjusted EBITDAX	$	76,537,560	$	54,079,485

Liquidity and Capital Resources

Historically, the Partnership’s principal sources of liquidity have been cash on hand, the cash flow generated from the Sanish Field Assets, and availability under the Partnership’s revolving credit facility, if any.

The Partnership generated approximately $74.7 million and $43.5 million in cash flow from operating activities for the years ended December 31, 2022 and 2021. In May 2021, the Partnership successfully refinanced its existing Simmons Bank credit facility and used the initial closing proceeds of approximately $40 million from the refinancing with BancFirst to fully repay the outstanding balance on the Simmons credit facility.

The Partnership incurred approximately $49.3 million in capital expenditures during 2022 on new well investment. As of December 31, 2022, approximately 74 of the 80 wells in the Partnership’s current drilling program have been completed and were producing, but the Partnership was only receiving revenue proceeds from 62 of the 74 completed wells. For non-operator, working-interest owners in oil and natural gas wells like the Partnership, there is a delay between when capital is invested to drill new wells and when the cash is actually received, as operators are permitted a grace period under the joint operating agreements that govern the operator and working interest owner relationship. Specific to the Partnership, to bridge the time gap from investment to incremental operational cash flow, the Partnership borrowed on its credit facility during the third quarter of 2022 to pay its capital obligations as they became due under the drilling program. Using incremental cash flow received related to newly-completed wells, the Partnership has reduced its outstanding balance on the BF Credit Facility to approximately $18.5 million at the time of filing this Form 10-K.

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In conjunction with BancFirst’s semi-annual borrowing base redetermination process completed in March 2023, the BF Loan Agreement was amended, of which changes included a reduction in the Partnership’s borrowing base to a fixed $30 million. As a result, the Partnership anticipates its cash on-hand, cash flow from operations and availability under the BF Credit Facility will be adequate to meet its liquidity requirements for at least the next 12 months, including completing the outstanding capital expenditures discussed below. The March 2023 BF Loan Agreement amendment also eliminated the Restricted Payment Clause within the loan agreement, whereby the Partnership may now make distributions to limited partners regardless of BF Credit Facility utilization so long as the Partnership is in compliance with the applicable covenants and no other event of default has occurred. Therefore, the General Partner will monitor payment of future monthly Partnership distributions in conjunction with the Partnership’s projected cash requirements for operations, payments on the BancFirst credit facility and capital expenditures for new wells.

The Partnership’s revenues and cash flow from operations are highly sensitive to changes in oil and natural gas prices and to levels of production. If commodity prices significantly drop, such as the decline in the second quarter of 2020, and remain low, the Partnership’s cash flow from operations may decline. This could have a significant impact on the Partnership’s available cash on-hand, the Partnership’s ability to participate in future drilling programs as proposed by the operators of the Sanish Field Assets and/or to fund any future distributions to its limited partners. Future growth is dependent on the Partnership’s ability to add reserves in excess of production. In addition to commodity price fluctuations, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.

Financing

See further discussion on the Partnership’s BF Credit Facility in “Note 4 – Debt” in Part II, Item 8 – Financial Statements and Supplementary Data appearing elsewhere in this Annual Report on Form 10-K.

Partners Equity

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 sold approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.

Under the agreement with the Dealer Manager, the Dealer Manager received a total of 6% in selling commissions and a 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 in “Distributions” below.

Distributions

See the definition and discussion of “Payout” in Note 7. Capital Contribution and Partners’ Equity in Part II, Item 8 – Financial Statements and Supplementary Data.

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. The Partnership successfully met the required conditions under its BancFirst credit agreement to resume distributions to limited partners in November 2021. For the year ended December 31, 2022, the Partnership paid distributions of $1.258082 per common unit, or $23.9 million. In addition, the Partnership declared a distribution of $0.138082 per common unit, or approximately $2.6 million, in December 2022; the distribution was accrued as of December 31, 2022, included in Accounts payable and accrued expenses on the Partnership’s consolidated balance sheet, and was paid in January 2023 (see “Subsequent Events” below). For the year ended December 31, 2021, the Partnership declared and paid distributions of $0.189863 per common unit, or $3.6 million.

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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 of December 31, 2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.

The General Partner monitors monthly Partnership distributions in conjunction with the Partnership’s projected cash requirements for operations and capital expenditures for new wells. There can be no assurance as to the classification or duration of distributions at the current distribution rate. As discussed above, if distributions are not paid or are reduced, the difference to the current distribution rate of $1.40 per common unit will be deferred and is required to be paid before final Payout occurs.

Oil and Natural Gas Properties

The Partnership incurred approximately $49.3 million and $23.1 million in capital expenditures for the years ended December 31, 2022 and 2021, respectively.

Since the beginning of 2019, the Partnership has elected to participate in the drilling and completion of 80 new wells in the Sanish field. As of December 31, 2022, approximately 74 of those 80 wells have been completed and were producing; the Partnership has an approximate non-operated working interest of 21% in these 74 wells. The Partnership has an estimated approximate non-operated working interest of 12% in 6 wells that are in-process as of December 31, 2022. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 61 wells is approximately $111 million, of which approximately $108 million was incurred as of December 31, 2022.

The Partnership anticipates its operators to complete the remaining 6 wells during the first quarter of 2023; however, completion of the wells is not in the Partnership’s control. The Partnership estimates the approximate $2 to $4 million in capital expenditures to fully pay for its recently-completed wells and to complete the other 6 wells in various stages of the drilling and completion process will be incurred through the first quarter of 2023 based on the best available information regarding current capital investment plans from its operators. Many factors outside the Partnership’s control make it difficult to predict the amount and timing of capital expenditures for 2023, and estimated capital expenditures could be significantly different from amounts actually invested. The Partnership anticipates that it may be obligated to invest an additional $15 to $20 million in capital expenditures in 2023, and an additional $75 to $80 million from 2024 through 2027 to participate in new well development in the Sanish Field without becoming subject to non-consent penalties under the joint operating agreements governing the Sanish Field Assets.

As described above, the Partnership’s liquidity is currently dependent upon cash on-hand, cash from operations and availability under the BF Credit Facility. If the Partnership is not able to generate sufficient cash from operation or there is no availability under the BF Credit Facility to fund capital expenditures, it may not be able to complete its capital obligations presented by its operators or participate fully in future wells. If an operator elects to complete drilling or other significant capital expenditure activity and the Partnership is unable to fund the capital expenditures, the General Partner may decide to farmout the well. Also, if a well is proposed under the operating agreement for one of the properties the Partnership owns, the General Partner may elect to “non-consent” the well. 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.

Oil, Natural Gas and NGL Reserves

The Partnership continually updates its proved undeveloped reserves (“PUD”) during its semiannual review based on current market conditions and future capital investment information provided by operators of the Sanish Field Assets as these factors may change the planned timing of drilling and completing PUD reserve locations within the SEC five-year window. 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 for complete information on the Partnership’s reserves as of December 31, 2022 and 2021.

Transactions with 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 existing related party transactions, as well as any new significant related party transactions.

See further discussion in Note 8. Related Parties in Part II, Item 8 – Financial Statements and Supplementary Data and in Part III, Item 13 — Certain Relationships and Related Transactions, and Director Independence, appearing elsewhere in this Annual Report on Form 10-K.

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Critical Accounting Policies and Estimates

The discussion and analysis of the Partnership’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these consolidated financial statements requires the Partnership to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. Certain of the Partnership’s accounting policies involve estimates and assumptions to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. The Partnership bases these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as the Partnership’s operating environment changes and as new events occur.

The Partnership’s critical accounting policies are important to the portrayal of both its financial condition and results of operations and require the Partnership to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. The Partnership would report different amounts in its consolidated financial statements, which could be material, if the Partnership used different assumptions or estimates. The Partnership believes that the following are the critical accounting policies used in the preparation of its consolidated financial statements.

Oil and Natural Gas Properties

The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when the Partnership is entering a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial, which will result in additional exploration expenses when incurred.

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Impairment

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Estimates of Oil, Natural Gas and Natural Gas Liquids Reserves

The Partnership’s estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production, both of which provide accurate forecasts. Non–producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. These methods provide accurate forecasts due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, the Partnership must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of the Partnership’s reserves. Independent reserve engineers prepare the Partnership’s reserve estimates at the end of each year.

Despite the inherent imprecision in these engineering estimates, the Partnership’s reserves are used throughout the Partnership’s financial statements. For example, since the Partnership uses the units–of–production method to amortize the costs of our oil and natural gas properties, the quantity of reserves could significantly impact its depreciation, depletion and amortization expense. The Partnership’s reserves are also the basis of the Partnership’s supplemental oil and natural gas disclosures.

Revenue Recognition

The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Oil, natural gas and natural gas liquids revenue receivable in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

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Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

Subsequent Events

In January 2023, the Partnership paid approximately $2.6 million, or $0.138082 per outstanding common unit, in distributions to its holders of common units.

In January 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.117671 per outstanding common unit for the month of January 2023. The distribution of approximately $2.2 million was paid on February 3, 2023 to common unit holders on record as of January 31, 2023.

In February 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.12 per outstanding common unit for the month of February 2023. The distribution of approximately $2.3 million was paid on March 3, 2023 to common unit holders on record as of February 28, 2023.

In March 2023, the Partnership and its Lender of the BF Credit Facility entered into an amendment to the BF Loan Agreement, resulting in the following changes effective as of the date of the amendment: (i) the borrowing base is fixed at $30 million; (ii) the Monthly Commitment Reduction, previously stipulated to be $1 million, has been eliminated; and (iii) the Restricted Payment Clause, which previously required the Partnership’s outstanding balance to be at or below 50% of the effective borrowing base to make distributions, has been eliminated.

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

Information regarding the Partnership’s hedging programs to mitigate commodity risks 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 6. Risk Management, appearing elsewhere within this Annual Report on Form 10-K.

The Partnership also has a variable interest rate on its BancFirst credit facility that is subject to market changes in interest rates. Information regarding the Partnership’s current, and prior, credit facilities 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 4. Debt, appearing elsewhere within this Annual Report on Form 10-K.

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Item 8. Financial Statements and Supplementary Data

Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders and the General Partner of Energy 11, L.P.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Energy 11, L.P. (the “Partnership”) as of December 31, 2022 and 2021, the related consolidated statements of operations, Partners’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2022 and 2021, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the Board of Directors and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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	Depreciation, Depletion, and Amortization of oil and natural gas properties
Description of the Matter	As of December 31, 2022, the net book value of the Partnership's oil and gas properties was $353.5 million, and depreciation, depletion and amortization (DD&A) expense was $21.0 million for the year then ended.  As more fully described in Note 2, capitalized costs of oil and natural gas properties are depleted using the unit-of-production method based on estimates of proved oil and natural gas reserves, as calculated by petroleum engineers with the assistance of management. Proved oil and natural gas reserve estimates are based on geological and petroleum engineering evaluations. Estimating reserves also requires the selection of subjective inputs, including future operating and capital costs assumptions, among others. Significant judgment is required by management including the Partnership’s petroleum engineering staff in evaluating the geological and engineering data and in determining the appropriate cost assumptions. Auditing the Partnership’s DD&A expense is especially complex because of the significant judgement by management in developing the estimate of proved oil and natural gas reserves and subjectivity of inputs used in estimating unit-of-production method based upon those reserves.
How We Addressed the Matter in Our Audit	Our audit procedures over the Partnership’s calculation of DD&A expense included, among others, evaluating the professional qualifications of the petroleum engineers and the Partnership’s management who performed the detailed preparation and review of the reserve estimates, respectively. We evaluated the completeness and accuracy of the financial data and inputs described above used by the petroleum engineers in estimating proved oil and natural gas reserves by agreeing them to source documentation, when available, and by identifying and evaluating corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management's development plan for compliance with SEC requirements. We also tested the mathematical accuracy of the unit-of-production calculations and compared the proved oil and natural gas reserves amounts used to calculate DD&A expense to the Partnership’s reserve report.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2021.

Richmond, Virginia

March 31, 2023

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Energy 11, L.P.

Consolidated Balance Sheets

	December 31,			December 31,
	2022			2021
Assets
Cash and cash equivalents	$	3,053,120		$	912,828
Accounts receivable		17,173,549			15,118,535
Other current assets, net		317,248			317,497
Total Current Assets		20,543,917			16,348,860
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $119,045,055 and $98,150,833, respectively		353,519,338			325,032,321
Other assets		23,654			165,578
Total Assets	$	374,086,909		$	341,546,759
Liabilities
Accounts payable and accrued expenses	$	15,170,168		$	9,847,984
Derivative liability		3,173,965			1,264,935
Total Current Liabilities		18,344,133			11,112,919
Revolving credit facility		22,600,000			23,000,000
Asset retirement obligations		1,966,738			1,791,341
Derivative liability - noncurrent		-			1,099,388
Total Liabilities		42,910,871			37,003,648
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)		331,177,765			304,544,838
General partner's interest		(1,727	)		(1,727	)
Class B units (62,500 units issued and outstanding, respectively)		-			-
Total Partners’ Equity		331,176,038			304,543,111
Total Liabilities and Partners’ Equity	$	374,086,909		$	341,546,759

See notes to consolidated financial statements.

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Energy 11, L.P.

Consolidated Statements of Operations

	Year Ended			Year Ended
	December 31, 2022			December 31, 2021
Revenues
Oil	$	94,755,037		$	61,396,251
Natural gas		8,625,891			5,511,526
Natural gas liquids		8,649,864			7,190,386
Total revenue		112,030,792			74,098,163
Operating costs and expenses
Production expenses		17,706,793			11,619,322
Production taxes		9,108,473			5,700,579
General and administrative expenses		2,074,306			1,516,357
Depreciation, depletion, amortization and accretion		20,974,139			22,473,437
Total operating costs and expenses		49,863,711			41,309,695
Operating income		62,167,081			32,788,468
Loss on derivatives, net		(7,272,374	)		(2,943,983	)
Interest expense, net		(1,456,700	)		(1,794,835	)
Total other expense, net		(8,729,074	)		(4,738,818	)
Net income	$	53,438,007		$	28,049,650
Basic and diluted net income per common unit	$	2.82		$	1.48
Weighted average common units outstanding - basic and diluted		18,973,474			18,973,474

See notes to consolidated financial statements.

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Energy 11, L.P.

Consolidated Statements of Partners’ Equity

	Limited Partner					Class B Units				General Partner			Total Partners'
	Common Units		Amount			Units		Amount		Amount			Equity
Balance December 31, 2020		18,973,474	$	280,347,549			62,500	$	-	$	(1,727	)	$	280,345,822
Distributions declared and paid to common units ($0.189863 per unit)		-		(3,602,361	)		-		-		-			(3,602,361	)
Estimated state tax withholding for limited partners		-		(250,000	)		-		-		-			(250,000	)
2021 Net income		-		28,049,650			-		-		-			28,049,650
Balance December 31, 2021		18,973,474		304,544,838			62,500		-		(1,727	)		304,543,111
Distributions declared to common units ($1.396164 per unit)		-		(26,490,080	)		-		-		-			(26,490,080	)
Estimated state tax withholding for limited partners		-		(315,000	)		-		-		-			(315,000	)
2022 Net income		-		53,438,007			-		-		-			53,438,007
Balance December 31, 2022		18,973,474	$	331,177,765			62,500	$	-	$	(1,727	)	$	331,176,038

See notes to consolidated financial statements.

56

Energy 11, L.P.

Consolidated Statements of Cash Flows

	Year Ended			Year Ended
	December 31, 2022			December 31, 2021
Cash flow from operating activities:
Net income	$	53,438,007		$	28,049,650
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion		20,974,139			22,473,437
Loss on mark-to-market of derivatives, net		668,714			1,761,563
Non-cash expenses, net		141,924			202,897
Changes in operating assets and liabilities:
Accounts receivable		(2,055,014	)		(9,227,564	)
Other assets		249			(26,331	)
Accounts payable and accrued expenses		1,573,440			240,592
Net cash flow provided by operating activities		74,741,459			43,474,244
Cash flow from investing activities:
Additions to oil and natural gas properties		(48,330,981	)		(18,020,757	)
Net cash flow used in investing activities		(48,330,981	)		(18,020,757	)
Cash flow from financing activities:
Cash paid for loan costs		-			(402,117	)
Proceeds from BancFirst revolving credit facility		13,600,000			40,063,389
Payments on BancFirst revolving credit facility		(14,000,000	)		(17,063,389	)
Payments on Simmons revolving credit facility		-			(40,000,000	)
Payments on affiliate term loan		-			(6,000,000	)
Distributions paid to limited partners		(23,870,186	)		(3,602,361	)
Net cash flow used in financing activities		(24,270,186	)		(27,004,478	)
Increase (decrease) in cash and cash equivalents		2,140,292			(1,550,991	)
Cash and cash equivalents, beginning of period		912,828			2,463,819
Cash and cash equivalents, end of period	$	3,053,120		$	912,828
Interest paid	$	1,260,325		$	1,553,451
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$	8,544,187		$	7,589,409

See notes to consolidated financial statements.

57

Energy 11, L.P.

Notes to Consolidated Financial Statements

December 31, 2022

Note 1. Partnership Organization

Energy 11, L.P. (together with its wholly-owned subsidiary, 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, 2022, the Partnership owns an approximate 24% non-operated working interest in 293 producing wells, an estimated approximate 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 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”). The General Partner manages and controls the business affairs of the Partnership.

The Partnership’s fiscal year ends on December 31.

Note 2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”). The consolidated financial statements include the accounts of the Partnership and its subsidiaries.

Cash, Cash Equivalents and Restricted Cash and Cash Equivalents

Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.

Property and Depreciation, Depletion and Amortization

The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of oil and natural gas properties are depleted using the unit-of-production method on a field basis based on estimated proved developed and/or undeveloped oil, natural gas and NGL reserves.

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

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The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Impairment

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Use of Estimates

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (“SEC”), the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected NYMEX forward strip prices for oil, natural gas and NGL as estimated by management are used. Oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of oil, natural gas and NGL reserves used in formulating management’s overall operating decisions.

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The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined.

Revenue Recognition

The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Oil, natural gas and natural gas liquids revenue receivable in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

Accounts Receivable and Concentration of Credit Risk

For the year ended December 31, 2022, the Partnership’s oil, natural gas and NGL sales were through two operators. Substantially all the Partnership’s accounts receivable is due from Chord, the largest operator of the Partnership’s oil and natural gas properties in North Dakota (operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2022, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. Chord is the current operator of 99% of the Partnership’s producing properties. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership.

Asset Retirement Obligation

The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.

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Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

The following table shows the activity for the years ended December 31, 2022 and 2021, relating to the Partnership’s asset retirement obligations:

Balance as of December 31, 2020	$	1,564,105
Well additions		139,343
Accretion		87,893
Revisions in estimated cash flows		-
Balance as of December 31, 2021		1,791,341
Well additions		95,480
Accretion		97,588
Revisions in estimated cash flows		(17,671	)
Balance as of December 31, 2022	$	1,966,738

Income Tax

The Partnership is taxed as a partnership for federal and state income tax purposes. Typically, the Partnership has not recorded a provision for income taxes since the liability for such taxes is that of each of the partners rather than the Partnership. 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. Therefore, the Partnership has recorded an estimate of North Dakota tax withholding on behalf of these certain non-resident limited partners for the tax years of 2021 and 2022 of approximately $0.6 million. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners.

The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.

Environmental Costs

As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved.

Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2022 and 2021, there were no such costs accrued.

Net Income Per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2022 and 2021. As a result, basic and diluted outstanding common units were the same. The Class B Units and Incentive Distribution Rights are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 7) would occur.

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Note 3. Oil and Gas Investments

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 86 new wells in the Sanish field, of which 80 of those 86 wells have been completed and were producing at December 31, 2022. The Partnership has 6 wells that are in-process as of December 31, 2022, which are expected to be completed during the first quarter of 2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells is approximately $119 million, of which approximately $116 million had been incurred as of December 31, 2022.

The Partnership estimates the approximate $2 to $4 million in capital expenditures to fully pay for its recently-completed wells along with the remaining 6 wells in various stages of drilling and completion will be incurred through the first quarter of 2023 based on the best available information regarding current capital investment plans from its operators. However, many factors outside the Partnership’s control make it difficult to predict the amount and timing of capital expenditures and estimated capital expenditures could be significantly different from amounts actually invested.

Note 4. Debt

Revolving Credit Facilities

In November 2017, the Partnership, as the borrower, entered into a loan agreement (the “Simmons Loan Agreement”) between and among the Partnership and Simmons Bank, as administrative agent and the lenders party thereto. Through various amendments, the Simmons Loan Agreement provided for a revolving credit facility (“Simmons Credit Facility”) with a commitment amount of $40 million, subject to borrowing base restrictions, that was to mature on July 31, 2021. The Simmons Credit Facility had an interest rate of 4.25% and outstanding borrowings of $40 million as of May 13, 2021.

On May 13, 2021, the Partnership and its wholly-owned subsidiary, as borrowers, entered into a loan agreement (“BF Loan Agreement”) with BancFirst, as administrative agent for the lenders (the “Lender”), which provides for a revolving credit facility (“BF Credit Facility”) with an approved maximum credit amount (“Maximum Credit Amount”) of $60 million, subject to borrowing base restrictions. The Partnership paid an origination fee of 0.50% of the Maximum Credit Amount, or $300,000, and is subject to an additional fee of 0.25% on any incremental increase to the borrowing base. Total capitalized loan costs were approximately $400,000 and are being amortized over the life of the BF Credit Facility. Approximately $166,000 million of the deferred loan costs remain unamortized as of December 31, 2022; approximately $142,000 are included in Other current assets, net and the other approximate $24,000 is recorded in Other assets on the Partnership’s consolidated balance sheet. The Partnership also is required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the Revolving Credit Facility, based on borrowings outstanding during a quarter. The maturity date is March 1, 2024.

At closing, the Partnership borrowed approximately $40 million. The proceeds were used to pay the $40 million outstanding balance and accrued interest on the Simmons Credit Facility described above. Any further advances under the BF Credit Facility are to be used to fund capital expenditures for the development of the Partnership’s undrilled acreage. Under the terms of the BF Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The BF Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells.

Under the BF Loan Agreement, the initial borrowing base was $60 million. The Partnership’s borrowing base is reduced by a Monthly Commitment Reduction, which is currently stipulated to be $1 million. Therefore, as of December 31, 2022, the borrowing base was $41 million. The borrowing base and Monthly Commitment Reduction are subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. In conjunction with the Lender’s March 1 redetermination analysis, the Partnership and Lender agreed to amend the BF Loan Agreement, including establishing a fixed borrowing base of $30 million and eliminating the Monthly Commitment Reduction. See additional information in Note 9. Subsequent Events. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period. Outstanding borrowings under the BF Credit Facility cannot exceed the lesser of the borrowing base or the Maximum Credit Amount at any time. The interest rate is equal to the Wall Street Journal Prime Rate plus 0.50%, with a floor of 4.00%.

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Also, the BF Loan Agreement requires to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production under certain conditions. As amended in August 2022, the Partnership is not required to enter into future hedging transactions as long as the Partnership maintains a BF Credit Facility utilization rate of less than or equal to 20% of the Partnership’s PV-9 (defined as the net present value, discounted at 9% per annum), as calculated by the Lender during the Lender’s scheduled semi-annual redeterminations described above. However, the Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the BF Credit Facility is greater than 20% but less than or equal to 30% of PV-9, and at least 50% of its rolling 24-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 30% of PV-9. Based on the Partnership’s utilization of the BF Credit Facility and Lender’s current calculation of PV-9, the Partnership was not subject to any additional hedging requirements under the amended BF Loan Agreement as of December 31, 2022.

See Note 6. Risk Management for more information on the Partnership’s risk management program as required under the BF Loan Agreement.

The BF Credit Facility contains prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants include:

● A minimum ratio of trailing 12-month EBITDAX to debt service coverage of 1.20 to 1.0

● A minimum ratio of current assets to current liabilities of 1.00 to 1.00

As amended in March 2023, the Partnership is permitted to make distributions to its limited partners so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred. The March 2023 amendment to the BF Loan Agreement eliminated the restriction on the Partnership’s ability to pay limited partner distributions if the outstanding balance of the BF Credit Facility was greater than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base (“Restricted Payment Clause”). See additional information in Note 9. Subsequent Events..

At December 31, 2022, the outstanding balance on the BF Credit Facility was approximately $22.6 million, and the interest rate was 8.00%. The Partnership was in compliance with its applicable covenants at December 31, 2022.

As of December 31, 2022 and 2021, the outstanding balances on the BF Credit Facility were approximately $22.6 million and $23.0 million, respectively, which approximated the fair market value. The Partnership estimated the fair value of its credit facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

Note 5. Fair Value of Financial Instruments

The Partnership follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows:

● Level 1: Quoted prices in active markets for identical assets

● Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument

● Level 3: Significant unobservable inputs

The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the years ended December 31, 2022 and 2021, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.

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As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021.

	Fair Value Measurements at December 31, 2022
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(3,173,965	)	$	-
Total	$	-	$	(3,173,965	)	$	-

	Fair Value Measurements at December 31, 2021
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(1,264,935	)	$	-
Commodity derivatives - noncurrent liabilities	$	-	$	(1,099,388	)	$	-
Total	$	-	$	(2,364,323	)	$	-

The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated by the Partnership using various methodologies and significant observable inputs, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performed an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considered that the counterparty is of substantial credit quality and had the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional detail in Note 6. Risk Management.

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments. In addition, see Note 4. Debt for the fair value discussion on the Partnership’s debt.

Note 6. Risk Management

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. The Partnership periodically 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 Note 4. Debt, 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 BF Loan Agreement (see Note 4. Debt) by entering into costless collar derivative contracts for the period from July 2021 to September 2023. The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars into which it entered to remain compliant with each loan agreement, and the contracts are settled monthly.

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As of December 31, 2022, the Partnership’s derivative instruments were in a loss position. The Partnership has recognized a total liability of approximately $3.2 million, of which the full balance has been recorded as current in Derivative liability on the Partnership’s consolidated balance sheet as of December 31, 2022. The Partnership’s derivative instruments were also in a loss position as of December 31, 2021. The Partnership recognized a total liability of approximately $2.4 million, of which $1.3 million has been recorded as current in Derivative liability and $1.1 million has been recorded as Derivative liability – noncurrent on the Partnership’s consolidated balance sheet as of December 31, 2021. These current and noncurrent derivative liabilities as of December 31, 2022 and 2021 approximate fair value.

The Partnership did not designate its 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 the settlement losses of matured derivative instruments and non-cash mark-to-market losses for the periods presented.

	Year Ended December 31, 2022			Year Ended December 31, 2021
Settlements on matured derivatives	$	(6,603,660	)	$	(1,182,420	)
Loss on mark-to-market of derivatives, net		(668,714	)		(1,761,563	)
Loss on derivatives	$	(7,272,374	)	$	(2,943,983	)

Settlements on matured derivatives reflect realized gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash, unrealized) gains or losses represent the change in fair value of derivative instruments which were held at period-end. Unrealized gains or 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.

Settlement Period	Basis	Product	Volume	Weighted Average Floor / Ceiling Prices ($)
01/2023 - 09/2023	NYMEX	Oil (bbls)	224,000	50.00 / 69.72
02/2023 - 09/2023	Henry Hub	Gas (MMbtu)	275,000	2.00 / 4.30

The Partnership’s outstanding derivative instrument is covered by an International Swap Dealers Association Master Agreement (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with the counterparty that provide for offsetting payables against receivables from separate derivative instruments. The use of derivative instruments involves the risk that the Partnership’s counterparty will be unable to meet the financial terms of such instruments.

Note 7. Capital Contribution and Partners’ Equity

At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering the organizational limited partner withdrew its initial capital contribution of $990, the General Partner received Incentive Distribution Rights (defined below), and was reimbursed for its documented third-party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.

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.

Under the agreement with the Dealer Manager, the Dealer Manager received a total of 6% in selling commissions and a 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 best-efforts offering, the total contingent fee is approximately $15.0 million.

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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 or record any liability with respect to the Incentive Distribution Rights (owned by the General Partner), the Class B units or the contingent, incentive payments to the Dealer Manager until an event that triggers 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:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).

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. The Partnership successfully met the required conditions under its BancFirst credit agreement to resume distributions to limited partners in November 2021. The outstanding balance on the BF Credit Facility increased to an amount greater than 50% of the applicable borrowing base during the third quarter of 2022, which required the Partnership to obtain a temporary waiver of the Restricted Payment Clause within the BF Loan Agreement from the Lender in September 2022 to make distributions to its limited partners for the months of September 2022, October 2022 and November 2022.

The Partnership declared a distribution of $0.138082 per common unit, or approximately $2.6 million, in December 2022. The distribution was accrued as of December 31, 2022, included in Accounts payable and accrued expenses on the Partnership’s consolidated balance sheet, and was paid in January 2023. Prior to the distribution payment made in January 2023, the Partnership had made an approximate $2.6 million principal payment on the BF Credit Facility to bring the Partnership in compliance with the Restricted Payment Clause at time of payment. The Restricted Payment Clause was eliminated from the BF Loan Agreement in the March 2023 amendment to the BF Loan Agreement, as described in Note 9. Subsequent Events.

For the year ended December 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.

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, 2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.

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Note 8. Related Parties

The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer, David S. McKenney, Chief Financial Officer, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Mr. Knight and Mr. McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and natural gas properties on-shore in the United States. Entities owned by Messrs. Keating and Mallick own non-voting, Class B units in the general partner of ER12.

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.

For the years ended December 31, 2022 and 2021, approximately $165,000 and $135,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At December 31, 2022 and 2021, approximately $57,000 and $44,000, respectively, was due to a member of the General Partner; these costs are included in Accounts payable and accrued expenses in the consolidated balance sheets.

On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and ER12, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of the Partnership. The ASA became effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or ER12 ceases to own its respective oil and natural gas assets. Provided the ASA is not terminated by any party via 60-day written notice at the conclusion of the Initial Term, the ASA will be automatically renewed for additional one-year periods. If a party to the ASA materially breaches the terms and conditions of the ASA and the breach has not been cured with 30 days of written notification of said breach, the ASA may be terminated with immediate effect.

Costs and expenses attributable to the services performed by the Administrator under the ASA will be reimbursed by the Partnership. All Administrator costs and expenses will be accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses to be reimbursed under the ASA may include, but are not limited to, employee wages and benefits, rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. For the years ended December 31, 2022 and 2021, approximately $634,000 and $586,000 of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator, respectively.

Under the ASA, the Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick.

E11 Incentive Holdings, LLC (“Incentive Holdings”) was the owner of all Class B units outstanding (62,500) as of March 31, 2017. During the second quarter of 2017, Incentive Holdings transferred substantially all of its assets; on April 5, 2017, Incentive Holdings transferred 18,125 of the 62,500 Class B units to E11 Incentive Carry Vehicle, LLC, an affiliate of Incentive Holdings, for de minimis consideration. On April 6, 2017, the remaining 44,375 Class B units were acquired by Regional Energy Incentives, LP in exchange for approximately $98,000. Regional Energy Incentives, LP is owned by entities that are controlled by Messrs. Keating, Mallick and McKenney. The Class B units entitle the holder to certain distribution rights after Payout, as described in Note 7. Capital Contribution and Partners’ Equity.

Note 9. Subsequent Events

In January 2023, the Partnership paid approximately $2.6 million, or $0.138082 per outstanding common unit, in distributions to its holders of common units.

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In January 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.117671 per outstanding common unit for the month of January 2023. The distribution of approximately $2.2 million was paid on February 3, 2023 to common unit holders on record as of January 31, 2023.

In February 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.12 per outstanding common unit for the month of February 2023. The distribution of approximately $2.3 million was paid on March 3, 2023 to common unit holders on record as of February 28, 2023.

In March 2023, the Partnership and its Lender of the BF Credit Facility entered into an amendment to the BF Loan Agreement, resulting in the following changes effective as of the date of the amendment: (i) the borrowing base is fixed at $30 million; (ii) the Monthly Commitment Reduction, previously stipulated to be $1 million, has been eliminated; and (iii) the Restricted Payment Clause, which previously required the Partnership’s outstanding balance to be at or below 50% of the effective borrowing base to make distributions, has been eliminated.

Note 10. Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2022 and 2021 is as follows:

	2022			2021
Producing properties	$	296,175,283		$	246,974,543
Non-producing		176,389,110			176,208,611
		472,564,393			423,183,154
Accumulated depreciation, depletion and amortization		(119,045,055	)		(98,150,833	)
Net capitalized costs	$	353,519,338		$	325,032,321

Costs Incurred

For the years ended December 31, 2022 and 2021, the Partnership incurred the following costs in oil and natural gas producing activities:

	2022		2021
Development costs	$	49,381,239	$	24,217,681

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

The following unaudited information regarding the Partnership’s oil, natural gas and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved oil and natural gas reserves are those quantities of oil, natural gas and NGLs which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

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The independent consulting petroleum engineering firm of Pinnacle Energy of Oklahoma City, OK, prepared estimates of the Partnership’s oil, natural gas and NGL reserves as of December 31, 2022, 2021 and 2020.

The Partnership’s net proved oil, NGL and natural gas reserves, all of which are located in the contiguous United States, as of December 31, 2022, 2021 and 2020, have been estimated by the Partnership’s independent consulting petroleum engineering firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with SEC rules and regulations along with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate. Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available. “Revisions of previous estimates” in the table below represent changes in previous reserve estimates, either upward or downward, resulting from a change in economic factors, such as commodity prices, operating costs or development costs, or resulting from information obtained from the Partnership’s production history.

The rollforward of net quantities of proved developed and undeveloped oil, natural gas and NGL reserves are summarized as follows:

	Proved Reserves
	Oil			Natural Gas			NGLs
	(Bbls)			(Mcf)			(Bbls)			Total (BOE)
December 31, 2020		14,414,175			16,798,230			2,628,494			19,842,374
Acquisition		-			-			-			-
Extensions, discoveries and other additions (1)		1,484,190			1,680,394			241,907			2,006,163
Revisions of previous estimates (2)		1,169,401			3,581,458			301,081			2,067,393
Production		(967,069	)		(1,159,929	)		(164,851	)		(1,325,243	)
December 31, 2021		16,100,697			20,900,153			3,006,631			22,590,687
Acquisition		-			-			-			-
Extensions, discoveries and other additions (3)		1,266,835			1,125,029			160,090			1,614,430
Revisions of previous estimates (4)		4,719,015			3,782,400			508,067			5,857,482
Production		(1,054,619	)		(1,329,995	)		(190,503	)		(1,466,788	)
December 31, 2022		21,031,928			24,477,587			3,484,285			28,595,811

(1)	In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(2)	Revisions to previous estimates increased proved reserves by a net amount of 2,067 MBOE. These revisions result from 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule, offset by 691 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020.
(3)	In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(4)	Revisions to previous estimates increased proved reserves by a net amount of 5,857 MBOE. These revisions result from 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and 164 MBOE of upward adjustments attributable caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021, offset by 2,484 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021.

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In accordance with SEC Regulation S-X, Rule 4-10, as amended, the Partnership uses the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period. 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.

Net quantities of proved developed and proved undeveloped reserves at December 31, 2022, 2021 and 2020 are summarized in the table below.

	Oil		Natural Gas		NGLs
	(Bbls)		(Mcf)		(Bbls)		Total (BOE)
Proved developed reserves:
December 31, 2020		10,688,857		12,992,674		2,029,392		14,883,695
December 31, 2021		11,197,370		15,350,678		2,207,738		15,963,554
December 31, 2022		12,959,918		16,547,639		2,355,866		18,073,724
Proved undeveloped reserves:
December 31, 2020		3,725,318		3,805,556		599,102		4,958,679
December 31, 2021		4,903,327		5,549,475		798,893		6,627,133
December 31, 2022		8,072,010		7,929,948		1,128,419		10,522,087

The following details the changes in proved undeveloped reserves (PUD) for 2021 and 2022:

	BOE
Proved undeveloped reserves, December 31, 2020		4,958,679
Revisions of previous estimates (1)		2,852,020
Extensions, discoveries and other additions (2)		2,006,163
Conversion to proved developed reserves (3)		(3,189,729	)
Proved undeveloped reserves acquired		-
Proved undeveloped reserves, December 31, 2021		6,627,133
Revisions of previous estimates (4)		7,803,541
Extensions, discoveries and other additions (5)		1,614,430
Conversion to proved developed reserves (6)		(5,523,017	)
Proved undeveloped reserves acquired		-
Proved undeveloped reserves, December 31, 2022		10,522,087

(1)	The annual review of the PUDs resulted in a positive revision of approximately 2,852 MBOE. This revision was the result of 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule and 94 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2021 to December 31, 2020.
(2)	In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(3)	The Partnership completed 23 new wells during 2021; therefore, the Partnership converted these 23 wells to proved developed reserves during 2021, which resulted in a downward adjustment to PUDs of 3,190 MBOE.
(4)	The annual review of the PUDs resulted in a positive revision of approximately 7,804 MBOE. This revision was the result of 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and offset by 373 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2022 to December 31, 2021.
(5)	In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(6)	The Partnership completed 27 new wells during 2022; therefore, the Partnership converted these 27 wells to proved developed reserves during 2022, which resulted in a downward adjustment to PUDs of 5,523 MBOE.

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Based upon current information from its operators, the Partnership anticipates all current PUD locations will be drilled and converted to PDP within five years of the date they were added. PUD locations and associated reserves which are no longer projected to be drilled within five years from the date they were first booked as proved undeveloped reserves have been removed as revisions at the time that determination was made.

Standardized Measure of Discounted Future Net Cash Flows

Accounting standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Partnership has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year.

The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.

	2022			2021
Future cash inflows	$	2,209,148,928		$	1,125,263,104
Future production costs		(586,350,144	)		(365,741,504	)
Future development costs		(110,237,400	)		(63,988,780	)
Future net cash flows		1,512,561,384			695,532,820
10% annual discount		(864,351,720	)		(387,348,180	)
Standardized measure of discounted future net cash flows	$	648,209,664		$	308,184,640

Changes in the standardized measure of discounted future net cash flows are as follows:

	2022			2021
Standardized measure at beginning of period	$	308,184,640		$	72,886,760
Changes resulting from:
Acquisition of reserves		-			-
Extensions, discoveries and other additions		49,126,990			25,896,564
Sales of oil, natural gas and NGLs, net of production costs		(85,215,526	)		(56,778,262	)
Net changes in prices and production costs		240,520,851			167,970,653
Development costs incurred during the period		49,381,239			24,217,681
Revisions to previous estimates		150,980,130			96,257,622
Accretion of discount		30,861,199			7,298,783
Change in estimated future development costs		(95,629,859	)		(29,565,161	)
Standardized measure of discounted future net cash flows	$	648,209,664		$	308,184,640

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Partnership carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of the General Partner, of the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of the General Partner concluded that the Partnership’s disclosure controls and procedures were effective as of December 31, 2022 to provide reasonable assurance that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Partnership’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Partnership management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act. The Partnership has performed an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of the General Partner, of the effectiveness of our internal control over financial reporting. Partnership management assessed the effectiveness of its internal control over financial reporting as of December 31, 2022. Partnership management used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) to perform its assessment. Based on this assessment, Partnership management, including the Chief Executive Officer and Chief Financial Officer of the General Partner, concluded, that as of December 31, 2022, the Partnership’s internal control over financial reporting was effective based on those criteria.

Changes in Internal Control Over Financial Reporting

There has been no change in the Partnership’s internal control over financial reporting during the quarter ended December 31, 2022 that has materially affected, or is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

Item 9B. Other Information

None

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable

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PART III

Item 10. Directors, Executive Officers, and Corporate Governance

Directors and Executive Officers of the General Partner

As is the case with many partnerships, the Partnership does not directly employ officers, directors or employees. Its operations and activities are managed by the Board of Directors and executive officers of the General Partner. References to directors and executive officers are references to the directors and executive officers of the General Partner.

The following table sets forth the names, ages and offices of the present directors and executive officers of the General Partner as of December 31, 2022.

Name	Age	Position
Glade M. Knight	79	Chairman of the Board and Chief Executive Officer
David S. McKenney	60	Director and Chief Financial Officer and Secretary
Anthony Francis “Chip” Keating III	43	Director and Co-Chief Operating Officer
Michael J. Mallick	60	Director and Co-Chief Operating Officer
Clifford J. Merritt	62	President

The following is a biographical summary of the business experience of these directors and executive officers:

Glade M. Knight. Mr. Knight has been the Chairman of the Board and Chief Executive Officer of the General Partner since its formation in July 2013. Mr. Knight is also part owner of and the Chief Executive Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P., a partnership focused on investments in the oil and gas industry. Mr. Knight is the founder and has served as Executive Chairman of Apple Hospitality REIT, Inc. since May 2014, and previously served as Chairman and Chief Executive Officer since its inception. Mr. Knight was also the founder of each of the former Apple REIT Companies and served as their Chairman and Chief Executive Officer from inception until the companies were sold to a third party or merged with Apple Hospitality REIT, Inc. In addition, Mr. Knight served as Chairman and Chief Executive Officer of Cornerstone Realty Income Trust, Inc. from 1993 until it merged with a subsidiary of Colonial Properties Trust in 2005. Following the merger in 2005 until April 2011, Mr. Knight served as a trustee of Colonial Properties Trust. Cornerstone Realty Income Trust, Inc. owned and operated apartment communities in Virginia, North Carolina, South Carolina, Georgia and Texas. Mr. Knight is the founding Chairman of Southern Virginia University in Buena Vista, Virginia. He also is a member of the Advisory Board to the Graduate School of Real Estate and Urban Land Development at Virginia Commonwealth University. Additionally, he serves on the National Advisory Council for Brigham Young University and is a founding member of the University’s Entrepreneurial Department of the Graduate School of Business Management. On February 12, 2014, Mr. Knight, Apple REIT Seven, Inc. (“Apple Seven”), Apple REIT Eight, Inc. (“Apple Eight”), Apple REIT Nine, Inc. (“Apple Nine”) and their related advisory companies entered into settlement agreements with the SEC. Along with Apple REIT Seven, Apple REIT Eight, Apple REIT Nine and their advisory companies, and without admitting or denying the SEC’s allegations, Mr. Knight consented to the entry of an administrative order, under which Mr. Knight and the noted companies each agreed to cease and desist from committing or causing any violations of Sections 13(a), 13(b)(2)(A), 13(b)(2)(B), 14(a), and 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Rules 12b-20, 13a-1, 13a-13, 13a-14, 14a-9, and 16a-3 thereunder.

David S. McKenney. Mr. McKenney has been a Director and Chief Financial Officer and Secretary of the General Partner since its formation in July 2013. Mr. McKenney is also part owner of and the Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P., a partnership focused on investments in the oil and gas industry. Mr. McKenney was the President of Capital Markets of Apple REIT Ten, Inc. from its inception until it merged with Apple Hospitality REIT, Inc. in September 2016. Mr. McKenney previously served as President of Capital Markets for Apple Hospitality REIT, Inc. In addition, Mr. McKenney was the President of Capital Markets of Apple REIT Six, Inc., a real estate investment trust, from 2004 until the company merged with an affiliate of Blackstone Real Estate Partners VII in May 2013. Mr. McKenney served in the same capacity for Apple Hospitality Five, Inc., a lodging REIT, from 2002 until the company was sold to Inland American Real Estate Trust, Inc. in October of 2007, and Apple Hospitality Two, Inc., a lodging REIT, from 2001 until the company was sold to an affiliate of ING Clarion in May of 2007. From 1994 to 2001, Mr. McKenney served as Senior Vice President and Treasurer of Cornerstone Realty Income Trust, Inc., a REIT that owned and operated apartment communities in Virginia, North Carolina, South Carolina, Georgia and Texas. From 1992 to 1994, Mr. McKenney served as Chief Financial Officer for The Henry A. Long Company, a regional development firm located in Washington, D.C. From 1988 to 1992, Mr. McKenney served as a Controller at Bozzuto & Associates, a regional developer of apartments and condominiums in the Washington, D.C. area. Mr. McKenney holds Bachelor of Science degrees in Accounting and Management Information Systems from James Madison University.

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Anthony “Chip” Francis Keating III. Mr. Keating has been a Director and Co-Chief Operating Officer of the General Partner since its formation in July 2013. Through an entity controlled by Mr. Keating, Mr. Keating owns Class B, non-voting units in Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P., a partnership focused on investments in the oil and gas industry. Mr. Keating has been a principal with Rock Creek Capital, a real estate and oil and gas investment company, since March 2010. Mr. Keating also is an officer of the General Partner of Regional Energy Investors, LP, a partnership that provides consulting services in the oil and gas industry. He served on the board of Apple REIT Ten, Inc. until the merger with Apple Hospitality REIT, Inc. in September 2016. Mr. Keating is the Founder and a Director of the Oklahoma State Troopers Foundation, Inc. He also serves as a director for OU Health and as a trustee for the University Hospital Authorities Trust. Mr. Keating is a former Director and Gubernatorial appointee of The Oklahoma Law Enforcement Retirement System and in December 2020, Mr. Keating completed a two-year commitment to Oklahoma Governor Kevin J. Stitt as his Cabinet Secretary for Public Safety. Prior to founding Rock Creek Capital, Mr. Keating served as the Real Estate Development Manager for Chesapeake Energy Corporation in Oklahoma City, Oklahoma from March 2007 to March 2010. While at Chesapeake, Mr. Keating closed and transacted over $850 million in real estate transactions ranging from corporate headquarters, sale leasebacks, field offices, investment properties and raw land in urban natural gas plays for drill sites. Prior to joining Chesapeake, Mr. Keating worked as a commercial real estate broker with Trammell Crow Company from August 2004 to March 2007. While at Trammell Crow Company, he specialized in tenant representation and investment sales. Before joining Trammell Crow Company, he spent over three years as an Oklahoma State Trooper from May 2001 to August 2004. Mr. Keating received a Bachelor of Business Administration from Southern Methodist University.

Michael J. Mallick. Mr. Mallick has been a Director and Co-Chief Operating Officer of the General Partner since its formation in July 2013. Through an entity controlled by Mr. Mallick, Mr. Mallick owns Class B, non-voting units in Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P., a partnership focused on investments in the oil and gas industry. Mr. Mallick also is an officer of the General Partner of Regional Energy Investors, LP, a partnership that provides consulting services in the oil and gas industry. Mr. Mallick is the founder of Fort Worth, Texas-based Mallick Group, Inc., a real estate and energy-related investment firm. Mr. Mallick is a principal investor in various entities and serves as the principal officer of sponsoring and managing partners for numerous and diverse real estate investments and energy-related interests funded with established co-investment relationships with high net worth private investors, institutional investors and lenders. Mr. Mallick’s varied experience includes development of the 349-room Horseshoe Bay Marriott Resort Hotel, located in Horseshoe Bay, Texas (financed with a national pension fund); Sierra Vista, a redevelopment initiative in a public/private partnership with the City of Fort Worth, Texas, including the assemblage and acquisition of approximately 300 acres located within a concentration of blight inside the central city and resulting in environmental remediation and demolition of 1,000 crime-ridden apartment units and new quality affordable housing and shopping; and acquisition of a large multi-property portfolio of properties financed via a structured private placement offering with multiple institutional investors. Mr. Mallick serves on the Board of Directors of the Oklahoma State Troopers Foundation, Inc.

Clifford J. Merritt. On December 18, 2015, Mr. Merritt was appointed as President of the General Partner. Mr. Merritt had been a consultant to us since July 1, 2014, and to other private exploration and development companies since November 2013. Prior to that time and since 2004 he was employed by Chesapeake Energy Corporation. From 2010 to 2013 he served as Chesapeake’s Vice President Land – Southern Division and from 2005 to 2010 as Chesapeake’s Land Manager – Barnett Shale District. Before joining Chesapeake, he worked for Okland Oil, Ricks Exploration and Concho Resources during the years of 1990 through 2003, each of which is an independent oil and gas company. He has a B.B.A. from the University of Central Oklahoma. During his career, Mr. Merritt has been involved and managed the Land functions of numerous acquisitions and divestitures of oil and natural gas properties and supervised the drilling and completion of over 2,000 oil and gas wells throughout multiple states in the continental US. Additionally, Mr. Merritt provides consulting services to Regional Energy Investors, LP.

The General Partner

The General Partner is Energy 11 GP, LLC, which was formed in 2013 and has no operating history. The General Partner was formed and is owned by companies controlled by Glade M. Knight, David S. McKenney, Anthony “Chip” F. Keating III, and Michael J. Mallick.

The General Partner will not receive a management or similar fee for acting as General Partner and will not receive an offering and organization fee for organizing the Partnership. The Partnership will reimburse the General Partner and its affiliates for all general and administrative expenses incurred by the General Partner and its affiliates in managing the Partnership’s business. These costs and expenses will include the direct and indirect costs and expenses of employee compensation, rental, office supplies, travel and entertainment, printing, legal, accounting, advertising, marketing and overhead. The beneficial owners of the General Partner are not employees of the General Partner, and do not receive salary or other compensation from the General Partner or Partnership other than reimbursement of third-party costs and expenses and with respect to their equity interests in the Partnership.

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Code of Ethics

The General Partner has adopted a Code of Business Conduct and Ethics that applies to the executive officers of the General Partner and other persons performing services for the General Partner and the Partnership, generally. This Code of Business Conduct and Ethics is posted on the Partnership’s website, at www.energyeleven.com.

Audit and Compensation Committee

The Partnership does not have a formal compensation committee and the General Partner’s Board of Directors serves as the audit committee. Because the Partnership does not have and is not seeking to list any securities on a national securities exchange or on an inter-dealer quotation system, the Partnership is not subject to some of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, the Partnership is not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors. Accordingly, the Board of Directors has not made any determination as to whether any of the members of the Board of Directors or committees thereof would qualify as independent under the listing standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition. Additionally, for the same reason, the Partnership has not yet determined whether any of its directors is an audit committee financial expert.

Item 11. Executive Compensation

Summary Compensation

The following table summarizes, with respect to each of the Chief Executive Officer and the two other most highly compensated officers of the General Partner (the “Named Executive Officers”), information relating to the compensation paid by the Partnership for services rendered in all capacities during the fiscal years ended December 31, 2022 and 2021. Since the only person being paid any compensation by the Partnership or the General Partner is Mr. Merritt, the Named Executive Officers only include Mr. Knight, the Chief Executive Officer, and Mr. Merritt.

Name and Principal Position:	Year	Salary		Bonus		All Other Compensation		Total
Glade M. Knight	2022	$	—	$	—	$	—	$	—
Chairman of the Board and Chief Executive Officer	2021	$	—	$	—	$	—	$	—
Clifford J. Merritt	2022	$	181,645	$	17,500	$	—	$	199,145
President	2021	$	180,920	$	27,500	$	—	$	208,420

The Partnership does not directly employ any of the persons responsible for managing its business. Instead, the General Partner manages the Partnership’s day-to-day affairs and provides the Partnership with management and operating services. The owners of the General Partner will be reimbursed for documented out-of-pocket travel, entertainment and similar expenses incurred by them in connection with attending board of directors’ meetings or managing the Partnership’s business. The owners of the General Partner will not receive any salary, bonus or consulting fees for serving on the board of directors or managing the Partnership’s business other than distributions in accordance with the incentive distribution rights, if any.

For the years ended December 31, 2022 and 2021, Mr. Merritt’s annual base compensation was $350,000 and basic health benefits. Because Mr. Merritt is an employee of Administrator, the Partnership paid one-half of Mr. Merritt’s compensation and benefits during 2022 and 2021, while Energy Resources 12, L.P. (“ER12”) paid the other half. See more information on the Administrative Services Agreement below in Item 13, and elsewhere, of this Form 10-K. Mr. Merritt also has a 5% interest in the General Partner’s incentive distribution rights.

Outstanding Equity Awards at Fiscal Year-End

There were no outstanding equity awards for the named executive officers as of December 31, 2022, other than the Incentive Distribution Rights.

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Compensation of Directors

The employee and non-employee members of the General Partner’s board of directors do not receive compensation for their services as directors. However, the directors may be reimbursed for their expenses in attending board meetings.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth as of March 1, 2023 the beneficial ownership of the Partnership’s common units and Class B units that are owned by:

● all persons who, to the knowledge of the Partnership’s management team, beneficially own more than 5% of the Partnership’s common units;

● each executive officer of the General Partner; and

● all current directors and executive officers of the General Partner as a group.

Name of Beneficial Owner	Common Units Beneficially Owned		Percentage of Common Units Beneficially Owned		Class B Units Beneficially Owned		Percentage of Class B Units Beneficially Owned
Glade M. Knight 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		5,000		*		-		-
David S. McKenney 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		5,000		*		4,437		7	%
Anthony Francis "Chip" Keating III 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		5,000		*		19,969		32	%
Michael J. Mallick 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		5,000		*		19,969		32	%
Cliff Merritt 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		-		-		-		-
Directors and principal officers as a group (5 persons)		20,000		*		44,375		71	%

* Less than 1% of outstanding common units.

Class B Units

Regional Energy Incentives, LP, owned by entities that are controlled by Mr. Keating, Mr. Mallick and Mr. McKenney, owns 44,375 Class B units. The address of Regional Energy Incentives, LP is 3715 Camp Bowie Blvd, Fort Worth, Texas 76107. The remaining 18,125 Class B units are owned by E11 Incentive Carry Vehicle, LLC, an affiliate of Incentive Holdings, LLC. The address of E11 Incentive Carry Vehicle, LLC is 301 NW 63rd Street, Suite 400, Oklahoma City, Oklahoma 73116.

The Partnership may issue up to 37,500 additional Class B units, the amount of Class B units canceled in conjunction with the 2016 termination of the management services agreement the Partnership had with its former manager.

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Ownership of the General Partner

The General Partner is a limited liability company. The members of the General Partner and the membership interest owned are as follows:

● GKOG, LLC, owns a 25% membership interest in the General Partner. GKOG, LLC is a limited liability company owned by Mr. Knight and his immediate family.

● DMOG, LLC owns a 25% membership interest in the General Partner. DMOG, LLC is a limited liability company owned by Mr. McKenney and his immediate family.

● CFK Energy, LLC owns a 25% membership interest in the General Partner. CFK Energy, LLC is a limited liability company owned by Mr. Keating and his immediate family.

● Pope Energy Investors, LP, a limited partnership, owns a 25% membership interest in the General Partner. The General Partner and the limited partner interests of Pope Energy Investors, LP are owned by Mr. Mallick and his immediate family.

Each member of the General Partner has the right to appoint one person to the General Partner’s board of directors. All decisions regarding the business of the General Partner and the Partnership will be made by the board of directors of the General Partner at meetings of the board of directors at which a quorum is present. The presence of a majority of the directors constitutes a quorum, and the vote of a majority of a quorum constitutes a decision by the board of directors.

The owners of the members of the General Partner have granted each other the right of first refusal to acquire any interests in the members of the General Partner that the owners propose to sell. If the owners of the members of the General Partner do not exercise the right of first refusal, the purchaser of the owner of the General Partner will have the right to appoint a member to the board of directors, and if a person or group of affiliated persons were to acquire a controlling interest in three of the owners of the General Partner, the person would be able to control the General Partner and the Partnership. The Partnership Agreement does not give the holders of common units the right to cause an owner of the General Partner to exercise its buy-sell right, or provide the holders the right to consent to or otherwise approve the transfer by an owner of the General Partner of its membership interest in the General Partner. The General Partner does, however, agree not to permit a change of control of the General Partner to occur. A change of control is defined as a person who is not currently a beneficial owner of the General Partner or a “qualifying owner” becoming the beneficial owner of 50% or more of the membership interest in the General Partner. A qualifying owner generally is defined as the following with respect to the current beneficial owners of the General Partner: conservators, guardians, executors, administrators, and similar persons of any trust, private foundation or custodianship that such beneficial owner, his spouse, lineal descendants or estate is a beneficiary.

Securities Authorized for Issuance under Equity Compensation Plans

The Partnership does not have any equity compensation plans.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Reimbursement of Expenses to General Partner in Connection with Operations of the Partnership

The Partnership will also reimburse the General Partner and the General Partner’s affiliates for their general and administrative costs allocable to the Partnership. These expenses will include compensation expense, rent, travel, and other general and administrative and overhead expenses. Currently, the only business of the General Partner is to act as General Partner of the Partnership, and all of the General Partner’s general and administrative costs will be paid by the Partnership. If affiliates of the General Partner form other partnerships or engage in other oil and gas activities, the General Partner will allocate its general and administrative costs to the Partnership and other partnerships or businesses in a manner deemed reasonable by the General Partner.

During the years ended December 31, 2022 and 2021, approximately $165,000 and $135,000, respectively, of related party costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership in connection with its operations.

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Incentive Distribution Rights

On the initial closing date, the Partnership issued incentive distribution rights, which are nonvoting limited partner interests that entitle the holder of such rights to 35% of all amounts distributed by the Partnership after Payout occurs, to the General Partner.

Administrative Services Agreement

On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and ER12, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of the Partnership. The ASA became effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or ER12 ceases to own its respective oil and natural gas assets. Provided the ASA is not terminated by any party via 60-day written notice at the conclusion of the Initial Term, the ASA will be automatically renewed for additional one-year periods. If a party to the ASA materially breaches the terms and conditions of the ASA and the breach has not been cured with 30 days of written notification of said breach, the ASA may be terminated with immediate effect.

Costs and expenses attributable to the services performed by the Administrator under the ASA will be reimbursed by the Partnership. All Administrator costs and expenses will be accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses to be reimbursed under the ASA may include, but are not limited to, employee wages and benefits, rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. For the years ended December 31, 2022 and 2021, approximately $634,000 and $586,000 of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator.

Under the ASA, the Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. The Administrator is owned by entities that are controlled by Anthony F. Keating, III and Michael J. Mallick, Co-Chief Operating Officers of the General Partner.

Consulting Fees to Clifford Merritt

On December 18, 2015, the General Partner appointed Clifford J. Merritt as its President. Prior to being appointed President, Mr. Merritt provided consulting services to the General Partner. Effective January 1, 2021, Mr. Merritt’s annual base compensation was adjusted to $350,000 plus basic health benefits; the General Partner agreed to pay Mr. Merritt an annual base compensation of $175,000, plus benefits, and was paid through the Administrative Services Agreement described above. For the years ended December 31, 2022 and 2021, Mr. Merritt was paid $199,145 and $208,420 by the Partnership. The other half of Mr. Merritt’s compensation was paid by ER12, as permitted by ER12’s general partner, in accordance with the Administrative Services Agreement.

Director Independence

Because the Partnership does not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, the Partnership is not required to have a board of directors comprised of a majority of independent directors under SEC rules or any listing standards. Accordingly, the Board of Directors of the General Partner has not made any determination as to whether the non-employee directors satisfy any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition.

Item 14. Principal Accountant Fees and Services

Ernst and Young LLP (“EY”) has audited the Partnership’s consolidated financial statements for the most recent fiscal year ended December 31, 2022. EY was selected and appointed as the Partnership’s independent registered public accounting firm on April 13, 2021.

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For the fiscal years ended December 31, 2022 and 2021, fees paid or payable to EY for services performed in connection with the audit of the 2022 and 2021 financial statements, 2022 and 2021 interim reviews and tax return preparation and compliance for 2022 and 2021 are included in the table below.

Audit Fees

	Year Ended December 31, 2022		Year Ended December 31, 2021
Audit fees	$	200,000	$	175,000
Audit-related fees		—		—
Tax fees		58,000		58,000
All other fees		—		—
Total	$	258,000	$	233,000

Pre-Approval Policies and Procedures

The General Partner currently has no Board committees. The Board of Directors has adopted policies regarding the pre-approval of auditor services. Specifically, the Board of Directors approves all services provided by the independent public accountants. The Board of Directors reviews the actual and budgeted fees for the independent public accountants periodically at regularly scheduled board meetings. All services provided by EY during the years ended December 31, 2022 and 2021 were approved by the Board of Directors.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Documents filed as part of this report:

1. Financial Statements:

(i) Report of Independent Registered Public Accounting Firm (PCAOB ID: 42) – Ernst & Young LLP

(ii) Consolidated Balance Sheets as of December 31, 2022 and December 31, 2021

(iii) Consolidated Statements of Operations for the years ended December 31, 2022 and 2021

(iv) Consolidated Statements of Partners’ Equity for the years ended December 31, 2022 and 2021

(v) Consolidated Statements of Cash Flows for the years ended December 31, 2022 and 2021

(vi) Notes to Financial Statements

2. Financial Statement Schedules:

(i) All schedules are omitted as they are not applicable, not required or the required information is included in the consolidated financial statements or notes thereto.

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3. Exhibits:

The following exhibits are included, or incorporated by reference, in this Annual Report on Form 10-K, for the year ended December 31, 2022 (and are numbered in accordance with Item 601 of Regulation S-K). Exhibits incorporated by reference to this Form 10-K as listed below are available at www.sec.gov.

EXHIBIT NUMBER	Description Of Exhibit
1.1	Exclusive Dealer Manager Agreement with David Lerner Associates, Inc. (incorporated by reference from Exhibit 1.1 to Amendment No. 7 to the Partnership’s Registration Statement on Form S-1 filed on December 31, 2014)
3.1	Certificate of limited partnership of Energy 11, L.P. (incorporated by reference from Exhibit 3.1 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1 filed on November 21, 2014)
3.2	First Amended and Restated Limited Partnership Agreement of Energy 11, L.P. dated as of August 19, 2015 (incorporated by reference from Exhibit A to the Prospectus included as part of the Amendment No. 6 to the Partnership’s Registration Statement on Form S-1 filed on December 12, 2014)
4.1	Description of Securities Registered Under Section 12 of the Exchange Act (incorporated by reference from Exhibit 4.1 to the Partnership’s Annual Report on Form 10-K filed on March 12, 2021)
10.1	Letter Agreement between Energy 11 GP, LLC and Clifford Merritt (incorporated by reference from Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed on December 21, 2015)
10.2	Administrative Services Agreement, dated December 1, 2020 and effective as of January 1, 2021, by and between Regional Energy Investors, L.P. d/b/a Regional Energy Management, Energy 11, L.P., Energy 11 Operating Company, LLC, Energy Resources 12, L.P. and Energy Resources 12 Operating Company, LLC (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on December 3, 2020)
10.3	Credit Agreement dated as of May 13, 2021 among Energy 11 Operating Company, LLC and Energy 11, L.P., as Borrowers, BancFirst, as Administrative Agent and the Lenders Party hereto (incorporated by reference from Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q filed on May 17, 2021)
10.4	First Amendment to Credit Agreement dated as of March 10, 2022 by and among Energy 11 Operating Company, LLC and Energy 11, L.P., as Borrowers, BancFirst, as Administrative Agent and the Lenders Party hereto (incorporated by reference from Exhibit 10.4 to the Partnership’s Annual Report on Form 10-K filed on March 16, 2022)
10.5	Second Amendment to Credit Agreement dated as of August 22, 2022 by and among Energy 11 Operating Company, LLC and Energy 11, L.P., as Borrowers, BancFirst, as Administrative Agent and the Lenders Party hereto (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on August 26, 2022)
10.6	Third Amendment to Credit Agreement dated effective as of March 24, 2023 by and among Energy 11 Operating Company, LLC and Energy 11, L.P., as Borrowers, BancFirst, as Administrative Agent and the Lenders Party hereto*
21.1	Subsidiaries of the Partnership*
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*
32.1	Certification of Chief Executive Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2	Certification of Chief Financial Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
99.1	Report of Pinnacle Energy Services, LLC, Independent Petroleum Consultants*
101	The following materials from Energy 11, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2022 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Partners’ Equity, (iv) the Consolidated Statements of Cash Flows, and (v) related notes to these consolidated financial statements, tagged as blocks of text and in detail*
104	The cover page from the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2022, formatted in iXBRL and contained in Exhibit 101

*Filed herewith.

Item 16. Form 10-K Summary

None

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ENERGY 11, L.P. By: Energy 11 GP, LLC, its General Partner
By:	/s/ David S. McKenney
	David S. McKenney
	Chief Financial Officer

Date: March 31, 2023

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title with General Partner	Date
/s/ Glade M. Knight	Director, Chief Executive Officer	March 31, 2023
	(principal executive officer)
/s/ David S. McKenney	Director, Chief Financial Officer	March 31, 2023
	(principal financial and accounting officer)
/s/ Anthony F. Keating III	Director, Co-Chief Operating Officer	March 31, 2023
/s/ Michael J. Mallick	Director, Co-Chief Operating Officer	March 31, 2023

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EX-10.6

Exhibit 10.6

THIRD AMENDMENT TO CREDIT AGREEMENT

THIS THIRD AMENDMENT TO CREDIT AGREEMENT is made effective as of March 24, 2023 (the “Amendment”), by and among ENERGY 11 OPERATING COMPANY, LLC, a Delaware limited liability company (“Energy 11 Operating”) and ENERGY 11, L.P., a Delaware limited partnership (“Energy 11 LP”; Energy 11 Operating and Energy 11 LP are jointly, severally and collectively referred to herein as the “Borrowers” and each individually as a “Borrower”), ENERGY 11 GP, LLC, a Delaware limited liability company (“the “Guarantor”), each of the Lenders from time to time party hereto, BANCFIRST, an Oklahoma chartered bank (in its individual capacity, “BancFirst”), as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).

W I T N E S S E T H:

WHEREAS, Borrowers and Lenders entered into that certain Credit Agreement executed on May 13, 2021 which such credit agreement has been amended from time to time and most recently by that certain Second Amendment to Credit Agreement dated as of August 22, 2022 (the “Existing Credit Agreement”), for the purpose and consideration therein expressed; and

WHEREAS, the loan described in the Existing Credit Agreement is currently evidenced by those certain promissory notes from Borrowers in favor of each of the Lenders dated as of May 13, 2021 in the aggregate principal amount of $60,000,000.00 (the “Existing Notes”);

WHEREAS, Borrowers and Lenders desire to amend the Existing Credit Agreement as set forth herein; and

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Existing Credit Agreement, in consideration of the loans and other extensions of credit which may hereafter be made by Bank to Borrower, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I.

DEFINITIONS AND REFERENCES

Section 1.1         Terms Defined in the Existing Credit Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Existing Credit Agreement shall have the same meanings whenever used in this Amendment.

Section 1.2         Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this Section 1.2.

“Amendment” means this Third Amendment to Credit Agreement.

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“Amendment Documents” means this Amendment, any amendments to existing security documents deemed necessary by Administrative Agent and all other Loan Documents executed and delivered in connection herewith.

“Credit Agreement” means the Existing Credit Agreement as amended hereby.

ARTICLE II.

AMENDMENTS TO EXISTING CREDIT AGREEMENT

Section 2.1.         Amendment to Section 9.04 of the Existing Credit Agreement. Section 9.04 of the Existing Credit Agreement is hereby amended and restated as follows:

9.04         Restricted Payments. The Borrowers will not, and will not permit any Subsidiary to, declare or make, or agree to pay or make, directly or indirectly, any Restricted Payment, return any capital to its stockholders or make any distribution of its Property to its Equity Interest holders, except:   Borrowers may declare and pay dividends ratably with respect to its Equity Interests, provided no Default or Event of Default has occurred and is continuing on the date any such distribution is declared or paid; and so long as, after giving effect to such distributions (i) the Debt Service Coverage Ratio (calculated on a pro forma basis in a manner reasonably acceptable to the Administrative Agent) is greater than or equal to 1.20 to 1.00, and (ii) no Default or Event of Default has occurred and is continuing on the date any such distribution is declared or paid.

ARTICLE III.

CONDITIONS OF EFFECTIVENESS

Section 4.1         Effective Date. This Amendment shall become effective as of the date first above written when and only when:

(a)         Amendment Documents. Bank shall have received duly executed and delivered counterparts of each Amendment Document (i) in form, substance and date satisfactory to Bank and (ii) in such numbers as Bank or its counsel may reasonably request.

(b)         Collateral Matters. Borrower shall have executed and delivered an amendment to any Loan Document including, additional mortgages or deeds of trust, deemed necessary by Bank.

(c)         Officer’s Certificate. Bank shall have received a certificate of the manager or other responsible officer of Borrower certifying as of the date of this Amendment (i) that there have been no changes to its organizational documents since the Closing Date, (ii) the resolutions of Borrower approving this Amendment, the other Amendment Documents and the related transactions, and (iii) the signature and incumbency certificates of the officers of Borrower (which certification may, if applicable, be by reference to previously delivered incumbency certificates).

(d)         Existence & Good Standing Certificates. Borrower shall be in existence and in good standing with the State of Oklahoma.

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(e)         Completion of Proceedings. All partnership, limited liability company, corporate and other proceedings taken or to be taken in connection with the transactions contemplated by this Amendment shall be reasonably satisfactory in form and substance to Bank.

(f)         Other Documentation. Bank shall have received all documents and instruments which Bank has then reasonably requested, in addition to those described in this Section 3.1. All such additional documents and instruments shall be reasonably satisfactory to Bank in form, substance and date.

(g)         No Default. No event shall have occurred and be continuing that would constitute an Event of Default or a Default.

(h)         Loan Fee. Administrative Agent and Lenders shall have received any loan fees due pursuant to the terms of the Existing Credit Agreement or any fee letter or other understanding.

ARTICLE IV.

REPRESENTATIONS AND WARRANTIES

Section 5.1         Representations and Warranties of Borrower. In order to induce Bank to enter into this Amendment, Borrower represents and warrants to Bank that:

(a)         All representations and warranties made by it in any Loan Document are true and correct in all material respects (without duplication of any materiality qualifier contained therein) on and as of time of the effectiveness hereof as if such representations and warranties had been made as of the time of the effectiveness hereof (except to the extent that such representation or warranty was made as of a specific date, in which case such representation or warranty shall be true and correct in all material respects (without duplication of any materiality qualifier contained therein) as of such specific date).

(b)         It has duly taken all limited liability company action necessary to authorize the execution and delivery by it of the Amendment Documents to which it is a party and to authorize the consummation of the transactions contemplated thereby and the performance of its obligations thereunder.

(c)         The execution and delivery by it of the Amendment Documents to which it is a party, the performance by it of its obligations under such Amendment Documents, and the consummation of the transactions contemplated by such Amendment Documents, do not and will not (a) conflict with, violate or result in a breach of any provision of (i), to its knowledge, any Law, (ii) its organizational documents, or (iii) any material agreement, judgment, license, order or permit applicable to or binding upon it, (b) result in the acceleration of any indebtedness owed by it, or (c) result in or require the creation of any lien upon any of its assets or properties except as expressly contemplated or permitted in the Loan Documents. Except (x) as expressly contemplated in the Amendment Documents and (y) such as have been obtained or made and are in full force and effect, to its knowledge, no permit, consent, approval, authorization or order of, and no notice to or filing with, any governmental authority or third party is required on the part of or in its respect

3

in connection with the execution, delivery or performance by it of any Amendment Document or to consummate any transactions contemplated by the Amendment Documents.

(d)         This Amendment is, and the other Amendment Documents when duly executed and delivered will be, legal, valid and binding obligations of it, enforceable against it in accordance with their terms except as such enforcement may be limited by bankruptcy, insolvency or similar Laws of general application relating to the enforcement of creditors’ rights and by general principles of equity.

ARTICLE V.

MISCELLANEOUS

Section 7.1         Borrowing Base. From the date hereof through the next Borrowing Base Determination, the Borrowing Base shall be $30,000,000.00, the Monthly Commitment Reduction shall be $0.00 and the Half Life shall be 60 months and the BancFirst roll forward September 1, 2023 PW9% value is $223,385M. Borrowers acknowledge that this Amendment satisfies all notification requirements set forth in the Agreement pertaining to the Borrowing Base.

Section 7.2         Ratification of Agreements. The Existing Credit Agreement as hereby amended is hereby ratified and confirmed in all respects. The Loan Documents, as they may be amended or affected by the various Amendment Documents, are hereby ratified and confirmed in all respects. Any reference to the Loan Agreement in any Loan Document shall be deemed to be a reference to the Existing Credit Agreement as hereby amended. The execution, delivery and effectiveness of this Amendment and the other Amendment Documents shall not, except as expressly provided herein or therein, operate as a waiver of any right, power or remedy of Bank under the Loan Agreement, the Note, or any other Loan Document nor constitute a waiver of any provision of the Loan Agreement, the Note or any other Loan Document.

Section 7.3         Waiver and Release. In consideration of the amendments contained herein, Borrower hereby waives and releases the Bank from any and all claims and defenses, known or unknown, with respect to the Existing Credit Agreement and the other Loan Documents and the transactions contemplated thereby. Borrower agrees to execute and deliver all documents and instruments requested by Bank in connection with the subject matter hereof, which shall be reasonably satisfactory to Bank in form, substance and date and each such document or instrument is a Loan Document.

Section 7.4         Survival of Agreements. All of Borrower’s various representations, warranties, covenants and agreements in the Amendment Documents shall survive the execution and delivery thereof and the performance thereof, including the making or granting of the Loans and the delivery of the other Loan Documents, and shall further survive until all of the Indebtedness is paid in full to Bank and all of Bank’s obligations to Borrower are terminated.

Section 7.5         Fees and Expenses. The Borrower hereby agrees to pay all reasonable attorney fees and legal expenses incurred by Bank in preparation, execution and implementation of this Amendment.

4

Section 7.6         Loan Documents. The Amendment Documents are each a Loan Document, and all provisions in the Existing Credit Agreement pertaining to Loan Documents apply thereto.

Section 7.7         Governing Law. This Amendment shall be governed by, and construed in accordance with, the Laws of the State of Oklahoma.

Section 7.8         Counterparts; Fax. This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. The Amendment Documents may be validly executed by facsimile or other electronic transmission.

THIS AMENDMENT AND THE OTHER AMENDMENT DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS OF THE PARTIES.

The remainder of this page has been left intentionally blank.

5

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the date first above written.

BORROWERS:	ENERGY 11 OPERATING COMPANY, LLC, a
	Delaware limited liability company
		By: ENERGY 11, L.P., a Delaware limited partnership
		Title: Sole Member
			By: ENERGY 11 GP, LLC, a  Delaware limited liability company
			Title: General Partner
			By: /s/ David McKenney
			David McKenney, Manager
	ENERGY 11, L.P.
	By: ENERGY 11 GP, LLC, a Delaware limited liability company
	Title: General Partner
	By: /s/ David McKenney
	David McKenney, Manager
GUARANTOR:	ENERGY 11 GP, LLC, a Delaware limited liability company
	By: /s/ David McKenney
	David McKenney, Manager

6

ADMINISTRATIVE AGENT/LENDER:	BANCFIRST, as Administrative Agent and a Lender
	By: /s/ Heather Healey Whiteside
	Heather Healey Whiteside, Vice President

7

LENDER:	MIDFIRST BANK
	By: /s/ Chay Kramer
	Chay Kramer, Vice President

8

LENDER:	GATEWAY FIRST BANK
	By: /s/ Charlie Crouse
	Charlie Crouse, Senior Commercial Banking Executive

Signature Page to Third Amendment to Credit Agreement

9

EX-21.1

EXHIBIT 21.1

Subsidiaries of the Partnership

The following are wholly owned subsidiaries of Energy 11, L.P.:

Energy 11 Operating Company, LLC (Formed in Delaware)

Energy 11 Management, LLC (Formed in Delaware)

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13a-14(a)/15D-14(a)

I, Glade M. Knight, certify that:

1. I have reviewed this Annual Report on Form 10-K of Energy 11, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 31, 2023	By:	/s/ Glade M. Knight
	Name:	Glade M. Knight
	Title:	General Partner, Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13a-14(a)/15D-14(a)

I, David S. McKenney, certify that:

1. I have reviewed this Annual Report on Form 10-K of Energy 11, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 31, 2023	By:	/s/ David S. McKenney
	Name:	David S. McKenney
	Title:	General Partner, Chief Financial Officer (Principal Financial and Accounting Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

This certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and accompanies the Annual Report on Form 10-K (the “Form 10-K”) for the year ended December 31, 2022 of Energy 11, L.P. (the “Partnership”). I, Glade M. Knight, the Chief Executive Officer of the Partnership, certify that, based on my knowledge:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Partnership as of and for the periods covered in this report.

Date: March 31, 2023	By:	/s/ Glade M. Knight
	Name:	Glade M. Knight
	Title:	General Partner, Chief Executive Officer (Principal Executive Officer)

The foregoing certification is being furnished as an exhibit to the Form 10-K pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Partnership, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

EX-32.2

EXHIBIT 32.2

CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

This certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and accompanies the Annual Report on Form 10-K (the “Form 10-K”) for the year ended December 31, 2022 of Energy 11, L.P. (the “Partnership”). I, David S. McKenney, the Chief Financial Officer of the Partnership, certify that, based on my knowledge:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Partnership as of and for the periods covered in this report.

Date: March 31, 2023	By:	/s/ David S. McKenney
	Name:	David S. McKenney
	Title:	General Partner, Chief Financial Officer (Principal Financial and Accounting Officer)

The foregoing certification is being furnished as an exhibit to the Form 10-K pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Partnership, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

EX-99.1

EXHIBIT 99.1

Energy 11, LP

5815 N. Western Avenue

Oklahoma City, OK 73118

Reserves and Economic Evaluation

Year-End 2022 Reserves

Non-Operated Assets located within the Sanish Oil Field located in Mountrail County, North Dakota

Effective: January 1, 2023

SEC Pricing

Prepared: February 7, 2023

By: John Paul (J.P.) Dick, P.E.

Candace Cantrell, P.E.

February 7, 2023

Energy 11, LP

5815 N. Western Avenue

Oklahoma City, OK 73118

Re: Reserve & Economic Evaluation

Non-Operated Assets in the Sanish Oil Field

Mountrail County, North Dakota

Year-End 2022 Reserves – SEC Price         

Executive Summary

An engineering and economic evaluation was prepared for oil and gas reserves located in the Williston Basin Sanish Field in Mountrail County, North Dakota in which Energy 11, LP (“Energy 11”) owns a working and/or royalty interest. The oil and gas reserves associated with these properties were evaluated and classified as Proved Reserves in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC). The Proved reserves include two hundred fifty-four (254) horizontal Proved Developed Producing (PDP) wells, forty-five (45) horizontal Proved Developed Non-Producing (PDNP) wells; thirty-nine (39) PDNP wells are waiting on workover or offset activity to return to production and six (6) PDNP wells have been commenced but are not yet on production; and fifty-seven (57) Proved Undeveloped (PUD) horizontal locations targeting the Bakken Shale and Three Forks formation in multiple sections/units. Also included in the attached economic reports is one (1) Proved Developed Shut-In (PDSI) well; however, this well was given no value or reserves for this evaluation. Remaining reserves, future cashflow, and present worth values were calculated as of January 1, 2023. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Energy 11.

Table 1 - Net Reserve and Economic Report Summary
Reserve Category	#	Oil	Gas	NGL	Net Cashflow	PV 10%
	Wells	(Mbbl)	(MMcf)	(Mbbl)	($M)	($M)
Proved	359	21,032	24,478	3,484	1,512,561	648,210
PDP	254	11,824	14,6126	2,080	881,480	421,322
PDNP	39	1,136	1,935	275	76,762	34,550
PDSI	2	0	0	0	0	0
PDNP	6	817	814	116	64,463	32,167
PUD	57	7,255	7,116	1,013	489,856	160,171
PA	1	0	0	0	0	0

The reserves and economics were determined using SEC YE2022 pricing as of January 1, 2023. Table 1 summarizes the estimated net reserves and future net revenue (cashflow), discounted and undiscounted, to the Energy 11 interest in these properties.

Economic Evaluation

Future Income

Future net revenue in this report includes deductions for state production taxes. Future net cashflow is after deducting state production taxes, future capital investments, and lease operating expenses but before consideration of any state and/or federal income taxes. For purposes of this evaluation, future capital investments include costs for drilling, completing, and equipping new wells. Abandonment costs of 100 M$ at the end of well life for each well have been included in this evaluation. The future net cashflow has not been adjusted for any outstanding loans that may exist, cash on hand, or undistributed income. Future net cashflow has been discounted at an annual rate of ten percent (10%) to determine its “present worth.” The present worth is shown to indicate the effect of time on the value of money. Future net revenue (cashflow) presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties evaluated.

Interests

Well and leasehold interests were provided by Energy 11 and are shown in Exhibit A. The non-operated interests average approximately 24% working interest and 19% net revenue interest.

Product Pricing

Per SEC rules, the SEC pricing is determined by calculating the unweighted arithmetic average of the first-day-of-the-month NYMEX oil and gas pricing for the prior twelve calendar months (January 2022 through December 2022) to the date of evaluation. All prices are held constant throughout the lives of the properties. For year-end 2022, the unweighted arithmetic average NYMEX (Cushing) oil price is 93.67 $/bbl and the average NYMEX (Henry Hub) natural gas price is 6.36 $/MMbtu. Prices were adjusted for quality, basis, energy content, transportation fees and other market differentials based on an analysis of revenue data.

Differentials to NYMEX pricing were calculated by examining Energy 11 revenue statements and financial information to determine deductions or increases to oil and gas prices due to Btu, differentials, and NGLs. The pricing differentials by operator are shown in Table 3.

Table 3 - Pricing Adjustments by Operator
	Oasis	Slawson	Whiting
Oil Price Differential, $/bbl	1.43	-2.79	-3.17
Residue Natural Gas Differential, $/Mcf	4.54	0.57	0.36
NGL Price, % of Oil	--	--	43%
Natural Gas Shrink, %	100.0%	64.0%	67.0%
NGL Yield, bbl/MMcf Wet Gas	--	--	95.34

Including the adjustments for quality, basis, energy content, transportation fees and other market differentials, the average realized prices held constant throughout the lives of the properties were 90.51 $/bbl oil, 6.75 $/Mcf natural gas and 40.28 $/bbl NGL.

Expenses

Expenses were calculated by examining historical financial information provided by Energy 11 to determine a fixed monthly rate and variable expenses to model the actual well life expense changes for all wells. Deductions for processing, transportation, and/or contract terms were also calculated for each product. Expenses were not escalated and are shown in Table 4.

Table 4 - Expenses and Deductions by Operator
	Oasis	Slawson	Whiting
Fixed Gross, $/well/month	5,500	5,500	5,500
Oil Variable Expense, $/bbl	4.10	4.10	4.10
Oil Deductions, $/bbl	4.50	0.00	0.47
Gas Deductions, $/mcf	3.04	0.05	2.75
NGL Deductions, $/bbl	--	--	11.50

Future Well Investments

Capital expenses for the future locations were estimated to be 7,200 M$/well, which is consistent with recent, actual industry drilling and completion costs for wells within the prospective area. Capital expenses for installation of an electric submersible pump (ESP) of 200 M$/well was also included at a cumulative production of 85 MBO for each future location. Capital timing for future development work was provided by Energy 11. Pinnacle cannot be responsible for capital costs that exceed or are less than these estimates.

Reserve Determination

RESERVE DISCUSSION

Remaining recoverable reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty depending primarily on the amount of reliable geologic and engineering (production, pressure) data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty is conveyed by classifying reserves as Proved (highly certain) or Non-Proved (less certain). The estimated reserves and revenues shown in this report were determined by SEC standards for Proved Developed Producing (PDP) wells, Proved Developed Non-Producing (PDNP), and Proved Undeveloped (PUD) locations.

Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs with defined limits and under current economic conditions, operating methods, and government regulations. Changes in any of these variables could materially change the reserves actually recovered.

Proved reserves are further classified as Proved Developed Producing (PDP) which is assigned to wells with sufficient production history to allow material balance and decline curve analysis to be the primary methods of estimation. PDP reserves are the most reliable reserves, generally with a high degree of confidence (>90%) that actually recovered quantities will equal or exceed published reserve estimates.

Proved Developed Non-Producing (PDNP) reserves include zones that have been penetrated by drilling but have not produced or have not produced in sufficient quantities to allow material balance or decline curve analysis with a high degree of confidence. This category includes wells awaiting completion. Also included in this category are wells that have temporarily stopped producing due to offset activity or workover operations but will return to production as soon as work has been commenced.

Proved Undeveloped (PUD) reserves are those quantities of petroleum that are estimated to be recovered from undrilled acreage (locations) in a continuous portion of the Proved Developed reservoir as defined by directly offsetting Proved Developed (PDP) wells and geological interpretations. The Proved Undeveloped wells are forecasted based on geological data presented, volumetric calculations, and analog comparisons to existing completions.

General

The reserves and values included in this report are estimates only and should not be construed as being exact quantities. The reserve estimates were performed using accepted engineering practices and were primarily based on historical rate decline analysis for existing producers. When possible and practical, volumetric calculations and analogies were integrated into the reserve estimates. As additional pressure and production performance data becomes available, reserve estimates may increase or decrease in the future. The revenue from such reserves and the actual costs related may be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the prices actually received for the reserves included in this report and the costs incurred in recovering such reserves may vary from the price and cost assumptions referenced. Therefore, in all cases, estimates of reserves may increase or decrease as a result of future operations. We consider all assumptions, data, and procedures utilized in this report appropriate for the purpose of this report.

In evaluating the information available for this analysis, items excluded from consideration were all matters as to which legal or accounting interpretation, rather than engineering interpretation, may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data and such conclusions necessarily represent only informed professional judgments.

Pinnacle Energy Services, LLC is an established petroleum engineering consulting firm. We hereby confirm that neither this firm, its affiliates, nor any of its employees, members, officers, or directors has, or is committed to acquire any interest, directly or indirectly, in the properties covered by this report, in any partnership, any general partner of the partnerships, nor is this firm or any employee, member or officer, or director thereof otherwise affiliated with any partnership or any such general partner. This report was completely independently prepared by Pinnacle Energy Services, LLC and our engagement and payment for services in connection with this report is independent of the outcome and not on a contingent basis.

The titles to the properties have not been examined nor has the actual degree or type of interest owned been independently confirmed. A field inspection of the properties is not usually considered necessary for the purpose of this report.

All information reviewed and utilized will be retained and is available for review by authorized parties at any time. Information used to prepare the evaluation was provided by Energy 11, LP, and was supplemented by public and in-house data. Pinnacle Energy Services, LLC can take no responsibility for the accuracy of the data used in the analysis, whether gathered from public sources or otherwise.

Pinnacle Energy Services, LLC

John Paul (J.P.) Dick, P.E. Petroleum Engineer Candace Cantrell, P.E. Petroleum Engineer

XML

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2022	Mar. 31, 2023	Jun. 30, 2022
Document Information Line Items
Entity Registrant Name	ENERGY 11, L.P.
Document Type	10-K
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		18,973,474
Entity Public Float			$ 0
Amendment Flag	false
Entity Central Index Key	0001581552
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Period End Date	Dec. 31, 2022
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
ICFR Auditor Attestation Flag	false
Document Annual Report	true
Document Transition Report	false
Entity File Number	000-55615
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-3070515
Entity Address, Address Line One	120 W 3rd Street, Suite 220
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	882-9192
Title of 12(g) Security	Common Units of Limited Partnership Interest
Entity Interactive Data Current	Yes
Auditor Name	Ernst & Young LLP
Auditor Location	Richmond, Virginia
Auditor Firm ID	42

XML

Consolidated Balance Sheets - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Assets
Cash and cash equivalents	$ 3,053,120	$ 912,828
Accounts receivable	17,173,549	15,118,535
Other current assets, net	317,248	317,497
Total Current Assets	20,543,917	16,348,860
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $119,045,055 and $98,150,833, respectively	353,519,338	325,032,321
Other assets	23,654	165,578
Total Assets	374,086,909	341,546,759
Liabilities
Accounts payable and accrued expenses	15,170,168	9,847,984
Derivative liability	3,173,965	1,264,935
Total Current Liabilities	18,344,133	11,112,919
Revolving credit facility	22,600,000	23,000,000
Asset retirement obligations	1,966,738	1,791,341
Derivative liability - noncurrent		1,099,388
Total Liabilities	42,910,871	37,003,648
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)	331,177,765	304,544,838
General partner's interest	(1,727)	(1,727)
Class B units (62,500 units issued and outstanding, respectively)	0	0
Total Partners’ Equity	331,176,038	304,543,111
Total Liabilities and Partners’ Equity	$ 374,086,909	$ 341,546,759

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Consolidated Balance Sheets (Parentheticals) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars)	$ 119,045,055	$ 98,150,833
Limited partners' interest, common units issued	18,973,474	18,973,474
Limited partners' interest, common units outstanding	18,973,474	18,973,474
Class B Units, units issued	62,500	62,500
Class B Units, units outstanding	62,500	62,500

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Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenues
Oil	$ 94,755,037	$ 61,396,251
Natural gas	8,625,891	5,511,526
Natural gas liquids	8,649,864	7,190,386
Total revenue	112,030,792	74,098,163
Operating costs and expenses
Production expenses	17,706,793	11,619,322
Production taxes	9,108,473	5,700,579
General and administrative expenses	2,074,306	1,516,357
Depreciation, depletion, amortization and accretion	20,974,139	22,473,437
Total operating costs and expenses	49,863,711	41,309,695
Operating income	62,167,081	32,788,468
Loss on derivatives, net	(7,272,374)	(2,943,983)
Interest expense, net	(1,456,700)	(1,794,835)
Total other expense, net	(8,729,074)	(4,738,818)
Net income	$ 53,438,007	$ 28,049,650
Basic and diluted net income per common unit (in Dollars per share)	$ 2.82	$ 1.48
Weighted average common units outstanding - basic and diluted (in Shares)	18,973,474	18,973,474

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Consolidated Statements of Partners' Equity - USD ($)	Total	Capital Unit, Class B [Member] Member Units [Member]	Limited Partner [Member]	General Partner [Member]
Balance at Dec. 31, 2020	$ 280,345,822		$ 280,347,549	$ (1,727)
Balance (in Shares) at Dec. 31, 2020		62,500	18,973,474
Distributions declared and paid to common units	(3,602,361)		$ (3,602,361)
Estimated state tax withholding for limited partners	(250,000)		(250,000)
Net income	28,049,650		28,049,650
Balance at Dec. 31, 2021	$ 304,543,111		$ 304,544,838	(1,727)
Balance (in Shares) at Dec. 31, 2021	18,973,474	62,500	18,973,474
Balance at Dec. 31, 2020	$ 280,345,822		$ 280,347,549	(1,727)
Balance (in Shares) at Dec. 31, 2020		62,500	18,973,474
Estimated state tax withholding for limited partners	600,000
Balance at Dec. 31, 2022	$ 331,176,038		$ 331,177,765	(1,727)
Balance (in Shares) at Dec. 31, 2022	18,973,474	62,500	18,973,474
Balance at Dec. 31, 2021	$ 304,543,111		$ 304,544,838	(1,727)
Balance (in Shares) at Dec. 31, 2021	18,973,474	62,500	18,973,474
Distributions declared to common units	$ (26,490,080)		$ (26,490,080)
Distributions declared and paid to common units	(23,870,186)
Estimated state tax withholding for limited partners	(315,000)		(315,000)
Net income	53,438,007		53,438,007
Balance at Dec. 31, 2022	$ 331,176,038		$ 331,177,765	$ (1,727)
Balance (in Shares) at Dec. 31, 2022	18,973,474	62,500	18,973,474

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Consolidated Statements of Partners' Equity (Parentheticals) - Capital Unit, Class B [Member] - Member Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Distributions declared and paid to common units, per unit		$ 0.189863
Distributions declared to common units	$ 1.396164

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Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cash flow from operating activities:
Net income (loss)	$ 53,438,007	$ 28,049,650
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion	20,974,139	22,473,437
Loss on mark-to-market of derivatives	668,714	1,761,563
Non-cash expenses	141,924	202,897
Changes in operating assets and liabilities:
Accounts receivable	(2,055,014)	(9,227,564)
Other assets	249	(26,331)
Accounts payable and accrued expenses	1,573,440	240,592
Net cash flow provided by operating activities	74,741,459	43,474,244
Cash flow from investing activities:
Additions to oil and natural gas properties	(48,330,981)	(18,020,757)
Net cash flow used in investing activities	(48,330,981)	(18,020,757)
Cash flow from financing activities:
Cash paid for loan costs	0	(402,117)
Proceeds from BancFirst revolving credit facility	13,600,000	40,063,389
Payments on BancFirst revolving credit facility	(14,000,000)	(17,063,389)
Proceeds from (payments on) Simmons revolving credit facility	0	(40,000,000)
Payments on affiliate term loan	0	(6,000,000)
Distributions paid to limited partners	(23,870,186)	(3,602,361)
Net cash flow provided by (used in) financing activities	(24,270,186)	(27,004,478)
Increase (decrease) in cash, cash equivalents and restricted cash	2,140,292	(1,550,991)
Cash, cash equivalents and restricted cash, beginning of period	912,828	2,463,819
Cash, cash equivalents and restricted cash, end of period	3,053,120	912,828
Interest paid	1,260,325	1,553,451
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$ 8,544,187	$ 7,589,409

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Partnership Organization

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

Note 1. Partnership Organization

Energy 11, L.P. (together with its wholly-owned subsidiary, 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, 2022, the Partnership owns an approximate 24% non-operated working interest in 293 producing wells, an estimated approximate 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 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”). The General Partner manages and controls the business affairs of the Partnership.

The Partnership’s fiscal year ends on December 31.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

Note 2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”). The consolidated financial statements include the accounts of the Partnership and its subsidiaries.

Cash, Cash Equivalents and Restricted Cash and Cash Equivalents

Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.

Property and Depreciation, Depletion and Amortization

The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of oil and natural gas properties are depleted using the unit-of-production method on a field basis based on estimated proved developed and/or undeveloped oil, natural gas and NGL reserves.

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Impairment

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Use of Estimates

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (“SEC”), the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected NYMEX forward strip prices for oil, natural gas and NGL as estimated by management are used. Oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of oil, natural gas and NGL reserves used in formulating management’s overall operating decisions.

The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined.

Revenue Recognition

The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Oil, natural gas and natural gas liquids revenue receivable in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

Accounts Receivable and Concentration of Credit Risk

For the year ended December 31, 2022, the Partnership’s oil, natural gas and NGL sales were through two operators. Substantially all the Partnership’s accounts receivable is due from Chord, the largest operator of the Partnership’s oil and natural gas properties in North Dakota (operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2022, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. Chord is the current operator of 99% of the Partnership’s producing properties. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership.

Asset Retirement Obligation

The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

The following table shows the activity for the years ended December 31, 2022 and 2021, relating to the Partnership’s asset retirement obligations:

Balance as of December 31, 2020	$	1,564,105
Well additions		139,343
Accretion		87,893
Revisions in estimated cash flows		-
Balance as of December 31, 2021		1,791,341
Well additions		95,480
Accretion		97,588
Revisions in estimated cash flows		(17,671	)
Balance as of December 31, 2022	$	1,966,738

Income Tax

The Partnership is taxed as a partnership for federal and state income tax purposes. Typically, the Partnership has not recorded a provision for income taxes since the liability for such taxes is that of each of the partners rather than the Partnership. 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. Therefore, the Partnership has recorded an estimate of North Dakota tax withholding on behalf of these certain non-resident limited partners for the tax years of 2021 and 2022 of approximately $0.6 million. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners.

The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.

Environmental Costs

As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved.

Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2022 and 2021, there were no such costs accrued.

Net Income Per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2022 and 2021. As a result, basic and diluted outstanding common units were the same. The Class B Units and Incentive Distribution Rights are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 7) would occur.

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Oil and Gas Investments

12 Months Ended

Dec. 31, 2022

Oil and Gas Property [Abstract]

Oil and Gas Properties [Text Block]

Note 3. Oil and Gas Investments

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 86 new wells in the Sanish field, of which 80 of those 86 wells have been completed and were producing at December 31, 2022. The Partnership has 6 wells that are in-process as of December 31, 2022, which are expected to be completed during the first quarter of 2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells is approximately $119 million, of which approximately $116 million had been incurred as of December 31, 2022.

The Partnership estimates the approximate $2 to $4 million in capital expenditures to fully pay for its recently-completed wells along with the remaining 6 wells in various stages of drilling and completion will be incurred through the first quarter of 2023 based on the best available information regarding current capital investment plans from its operators. However, many factors outside the Partnership’s control make it difficult to predict the amount and timing of capital expenditures and estimated capital expenditures could be significantly different from amounts actually invested.

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Debt

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

Note 4. Debt

Revolving Credit Facilities

In November 2017, the Partnership, as the borrower, entered into a loan agreement (the “Simmons Loan Agreement”) between and among the Partnership and Simmons Bank, as administrative agent and the lenders party thereto. Through various amendments, the Simmons Loan Agreement provided for a revolving credit facility (“Simmons Credit Facility”) with a commitment amount of $40 million, subject to borrowing base restrictions, that was to mature on July 31, 2021. The Simmons Credit Facility had an interest rate of 4.25% and outstanding borrowings of $40 million as of May 13, 2021.

On May 13, 2021, the Partnership and its wholly-owned subsidiary, as borrowers, entered into a loan agreement (“BF Loan Agreement”) with BancFirst, as administrative agent for the lenders (the “Lender”), which provides for a revolving credit facility (“BF Credit Facility”) with an approved maximum credit amount (“Maximum Credit Amount”) of $60 million, subject to borrowing base restrictions. The Partnership paid an origination fee of 0.50% of the Maximum Credit Amount, or $300,000, and is subject to an additional fee of 0.25% on any incremental increase to the borrowing base. Total capitalized loan costs were approximately $400,000 and are being amortized over the life of the BF Credit Facility. Approximately $166,000 million of the deferred loan costs remain unamortized as of December 31, 2022; approximately $142,000 are included in Other current assets, net and the other approximate $24,000 is recorded in Other assets on the Partnership’s consolidated balance sheet. The Partnership also is required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the Revolving Credit Facility, based on borrowings outstanding during a quarter. The maturity date is March 1, 2024.

At closing, the Partnership borrowed approximately $40 million. The proceeds were used to pay the $40 million outstanding balance and accrued interest on the Simmons Credit Facility described above. Any further advances under the BF Credit Facility are to be used to fund capital expenditures for the development of the Partnership’s undrilled acreage. Under the terms of the BF Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The BF Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells.

Under the BF Loan Agreement, the initial borrowing base was $60 million. The Partnership’s borrowing base is reduced by a Monthly Commitment Reduction, which is currently stipulated to be $1 million. Therefore, as of December 31, 2022, the borrowing base was $41 million. The borrowing base and Monthly Commitment Reduction are subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. In conjunction with the Lender’s March 1 redetermination analysis, the Partnership and Lender agreed to amend the BF Loan Agreement, including establishing a fixed borrowing base of $30 million and eliminating the Monthly Commitment Reduction. See additional information in Note 9. Subsequent Events. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period. Outstanding borrowings under the BF Credit Facility cannot exceed the lesser of the borrowing base or the Maximum Credit Amount at any time. The interest rate is equal to the Wall Street Journal Prime Rate plus 0.50%, with a floor of 4.00%.

Also, the BF Loan Agreement requires to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production under certain conditions. As amended in August 2022, the Partnership is not required to enter into future hedging transactions as long as the Partnership maintains a BF Credit Facility utilization rate of less than or equal to 20% of the Partnership’s PV-9 (defined as the net present value, discounted at 9% per annum), as calculated by the Lender during the Lender’s scheduled semi-annual redeterminations described above. However, the Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the BF Credit Facility is greater than 20% but less than or equal to 30% of PV-9, and at least 50% of its rolling 24-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 30% of PV-9. Based on the Partnership’s utilization of the BF Credit Facility and Lender’s current calculation of PV-9, the Partnership was not subject to any additional hedging requirements under the amended BF Loan Agreement as of December 31, 2022.

See Note 6. Risk Management for more information on the Partnership’s risk management program as required under the BF Loan Agreement.

The BF Credit Facility contains prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants include:

● A minimum ratio of trailing 12-month EBITDAX to debt service coverage of 1.20 to 1.0

● A minimum ratio of current assets to current liabilities of 1.00 to 1.00

As amended in March 2023, the Partnership is permitted to make distributions to its limited partners so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred. The March 2023 amendment to the BF Loan Agreement eliminated the restriction on the Partnership’s ability to pay limited partner distributions if the outstanding balance of the BF Credit Facility was greater than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base (“Restricted Payment Clause”). See additional information in Note 9. Subsequent Events..

At December 31, 2022, the outstanding balance on the BF Credit Facility was approximately $22.6 million, and the interest rate was 8.00%. The Partnership was in compliance with its applicable covenants at December 31, 2022.

As of December 31, 2022 and 2021, the outstanding balances on the BF Credit Facility were approximately $22.6 million and $23.0 million, respectively, which approximated the fair market value. The Partnership estimated the fair value of its credit facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

Note 5. Fair Value of Financial Instruments

The Partnership follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows:

● Level 1: Quoted prices in active markets for identical assets

● Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument

● Level 3: Significant unobservable inputs

The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the years ended December 31, 2022 and 2021, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021.

	Fair Value Measurements at December 31, 2022
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(3,173,965	)	$	-
Total	$	-	$	(3,173,965	)	$	-

	Fair Value Measurements at December 31, 2021
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(1,264,935	)	$	-
Commodity derivatives - noncurrent liabilities	$	-	$	(1,099,388	)	$	-
Total	$	-	$	(2,364,323	)	$	-

The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated by the Partnership using various methodologies and significant observable inputs, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performed an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considered that the counterparty is of substantial credit quality and had the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional detail in Note 6. Risk Management.

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments. In addition, see Note 4. Debt for the fair value discussion on the Partnership’s debt.

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Risk Management

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

Note 6. Risk Management

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. The Partnership periodically 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 Note 4. Debt, 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 BF Loan Agreement (see Note 4. Debt) by entering into costless collar derivative contracts for the period from July 2021 to September 2023. The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars into which it entered to remain compliant with each loan agreement, and the contracts are settled monthly.

As of December 31, 2022, the Partnership’s derivative instruments were in a loss position. The Partnership has recognized a total liability of approximately $3.2 million, of which the full balance has been recorded as current in Derivative liability on the Partnership’s consolidated balance sheet as of December 31, 2022. The Partnership’s derivative instruments were also in a loss position as of December 31, 2021. The Partnership recognized a total liability of approximately $2.4 million, of which $1.3 million has been recorded as current in Derivative liability and $1.1 million has been recorded as Derivative liability – noncurrent on the Partnership’s consolidated balance sheet as of December 31, 2021. These current and noncurrent derivative liabilities as of December 31, 2022 and 2021 approximate fair value.

The Partnership did not designate its 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 the settlement losses of matured derivative instruments and non-cash mark-to-market losses for the periods presented.

	Year Ended December 31, 2022			Year Ended December 31, 2021
Settlements on matured derivatives	$	(6,603,660	)	$	(1,182,420	)
Loss on mark-to-market of derivatives, net		(668,714	)		(1,761,563	)
Loss on derivatives	$	(7,272,374	)	$	(2,943,983	)

Settlements on matured derivatives reflect realized gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash, unrealized) gains or losses represent the change in fair value of derivative instruments which were held at period-end. Unrealized gains or 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.

Settlement Period	Basis	Product	Volume	Weighted Average Floor / Ceiling Prices ($)
01/2023 - 09/2023	NYMEX	Oil (bbls)	224,000	50.00 / 69.72
02/2023 - 09/2023	Henry Hub	Gas (MMbtu)	275,000	2.00 / 4.30

The Partnership’s outstanding derivative instrument is covered by an International Swap Dealers Association Master Agreement (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with the counterparty that provide for offsetting payables against receivables from separate derivative instruments. The use of derivative instruments involves the risk that the Partnership’s counterparty will be unable to meet the financial terms of such instruments.

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Capital Contribution and Partners' Equity

12 Months Ended

Dec. 31, 2022

Partners' Capital Notes [Abstract]

Partners' Capital Notes Disclosure [Text Block]

Note 7. Capital Contribution and Partners’ Equity

At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering the organizational limited partner withdrew its initial capital contribution of $990, the General Partner received Incentive Distribution Rights (defined below), and was reimbursed for its documented third-party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.

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.

Under the agreement with the Dealer Manager, the Dealer Manager received a total of 6% in selling commissions and a 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 best-efforts offering, the total contingent fee is approximately $15.0 million.

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 or record any liability with respect to the Incentive Distribution Rights (owned by the General Partner), the Class B units or the contingent, incentive payments to the Dealer Manager until an event that triggers 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:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).

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. The Partnership successfully met the required conditions under its BancFirst credit agreement to resume distributions to limited partners in November 2021. The outstanding balance on the BF Credit Facility increased to an amount greater than 50% of the applicable borrowing base during the third quarter of 2022, which required the Partnership to obtain a temporary waiver of the Restricted Payment Clause within the BF Loan Agreement from the Lender in September 2022 to make distributions to its limited partners for the months of September 2022, October 2022 and November 2022.

The Partnership declared a distribution of $0.138082 per common unit, or approximately $2.6 million, in December 2022. The distribution was accrued as of December 31, 2022, included in Accounts payable and accrued expenses on the Partnership’s consolidated balance sheet, and was paid in January 2023. Prior to the distribution payment made in January 2023, the Partnership had made an approximate $2.6 million principal payment on the BF Credit Facility to bring the Partnership in compliance with the Restricted Payment Clause at time of payment. The Restricted Payment Clause was eliminated from the BF Loan Agreement in the March 2023 amendment to the BF Loan Agreement, as described in Note 9. Subsequent Events.

For the year ended December 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.

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, 2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.

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Related Parties

12 Months Ended

Dec. 31, 2022

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

Note 8. Related Parties

The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer, David S. McKenney, Chief Financial Officer, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Mr. Knight and Mr. McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and natural gas properties on-shore in the United States. Entities owned by Messrs. Keating and Mallick own non-voting, Class B units in the general partner of ER12.

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.

For the years ended December 31, 2022 and 2021, approximately $165,000 and $135,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At December 31, 2022 and 2021, approximately $57,000 and $44,000, respectively, was due to a member of the General Partner; these costs are included in Accounts payable and accrued expenses in the consolidated balance sheets.

On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and ER12, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of the Partnership. The ASA became effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or ER12 ceases to own its respective oil and natural gas assets. Provided the ASA is not terminated by any party via 60-day written notice at the conclusion of the Initial Term, the ASA will be automatically renewed for additional one-year periods. If a party to the ASA materially breaches the terms and conditions of the ASA and the breach has not been cured with 30 days of written notification of said breach, the ASA may be terminated with immediate effect.

Costs and expenses attributable to the services performed by the Administrator under the ASA will be reimbursed by the Partnership. All Administrator costs and expenses will be accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses to be reimbursed under the ASA may include, but are not limited to, employee wages and benefits, rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. For the years ended December 31, 2022 and 2021, approximately $634,000 and $586,000 of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator, respectively.

Under the ASA, the Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick.

E11 Incentive Holdings, LLC (“Incentive Holdings”) was the owner of all Class B units outstanding (62,500) as of March 31, 2017. During the second quarter of 2017, Incentive Holdings transferred substantially all of its assets; on April 5, 2017, Incentive Holdings transferred 18,125 of the 62,500 Class B units to E11 Incentive Carry Vehicle, LLC, an affiliate of Incentive Holdings, for de minimis consideration. On April 6, 2017, the remaining 44,375 Class B units were acquired by Regional Energy Incentives, LP in exchange for approximately $98,000. Regional Energy Incentives, LP is owned by entities that are controlled by Messrs. Keating, Mallick and McKenney. The Class B units entitle the holder to certain distribution rights after Payout, as described in Note 7. Capital Contribution and Partners’ Equity.

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Subsequent Events

12 Months Ended

Dec. 31, 2022

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Note 9. Subsequent Events

In January 2023, the Partnership paid approximately $2.6 million, or $0.138082 per outstanding common unit, in distributions to its holders of common units.

In January 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.117671 per outstanding common unit for the month of January 2023. The distribution of approximately $2.2 million was paid on February 3, 2023 to common unit holders on record as of January 31, 2023.

In February 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.12 per outstanding common unit for the month of February 2023. The distribution of approximately $2.3 million was paid on March 3, 2023 to common unit holders on record as of February 28, 2023.

In March 2023, the Partnership and its Lender of the BF Credit Facility entered into an amendment to the BF Loan Agreement, resulting in the following changes effective as of the date of the amendment: (i) the borrowing base is fixed at $30 million; (ii) the Monthly Commitment Reduction, previously stipulated to be $1 million, has been eliminated; and (iii) the Restricted Payment Clause, which previously required the Partnership’s outstanding balance to be at or below 50% of the effective borrowing base to make distributions, has been eliminated.

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)

12 Months Ended

Dec. 31, 2022

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

Note 10. Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2022 and 2021 is as follows:

	2022			2021
Producing properties	$	296,175,283		$	246,974,543
Non-producing		176,389,110			176,208,611
		472,564,393			423,183,154
Accumulated depreciation, depletion and amortization		(119,045,055	)		(98,150,833	)
Net capitalized costs	$	353,519,338		$	325,032,321

Costs Incurred

For the years ended December 31, 2022 and 2021, the Partnership incurred the following costs in oil and natural gas producing activities:

	2022		2021
Development costs	$	49,381,239	$	24,217,681

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

The following unaudited information regarding the Partnership’s oil, natural gas and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved oil and natural gas reserves are those quantities of oil, natural gas and NGLs which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The independent consulting petroleum engineering firm of Pinnacle Energy of Oklahoma City, OK, prepared estimates of the Partnership’s oil, natural gas and NGL reserves as of December 31, 2022, 2021 and 2020.

The Partnership’s net proved oil, NGL and natural gas reserves, all of which are located in the contiguous United States, as of December 31, 2022, 2021 and 2020, have been estimated by the Partnership’s independent consulting petroleum engineering firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with SEC rules and regulations along with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate. Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available. “Revisions of previous estimates” in the table below represent changes in previous reserve estimates, either upward or downward, resulting from a change in economic factors, such as commodity prices, operating costs or development costs, or resulting from information obtained from the Partnership’s production history.

The rollforward of net quantities of proved developed and undeveloped oil, natural gas and NGL reserves are summarized as follows:

	Proved Reserves
	Oil			Natural Gas			NGLs
	(Bbls)			(Mcf)			(Bbls)			Total (BOE)
December 31, 2020		14,414,175			16,798,230			2,628,494			19,842,374
Acquisition		-			-			-			-
Extensions, discoveries and other additions (1)		1,484,190			1,680,394			241,907			2,006,163
Revisions of previous estimates (2)		1,169,401			3,581,458			301,081			2,067,393
Production		(967,069	)		(1,159,929	)		(164,851	)		(1,325,243	)
December 31, 2021		16,100,697			20,900,153			3,006,631			22,590,687
Acquisition		-			-			-			-
Extensions, discoveries and other additions (3)		1,266,835			1,125,029			160,090			1,614,430
Revisions of previous estimates (4)		4,719,015			3,782,400			508,067			5,857,482
Production		(1,054,619	)		(1,329,995	)		(190,503	)		(1,466,788	)
December 31, 2022		21,031,928			24,477,587			3,484,285			28,595,811

(1)	In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(2)	Revisions to previous estimates increased proved reserves by a net amount of 2,067 MBOE. These revisions result from 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule, offset by 691 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020.
(3)	In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(4)	Revisions to previous estimates increased proved reserves by a net amount of 5,857 MBOE. These revisions result from 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and 164 MBOE of upward adjustments attributable caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021, offset by 2,484 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021.

In accordance with SEC Regulation S-X, Rule 4-10, as amended, the Partnership uses the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period. 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.

Net quantities of proved developed and proved undeveloped reserves at December 31, 2022, 2021 and 2020 are summarized in the table below.

	Oil		Natural Gas		NGLs
	(Bbls)		(Mcf)		(Bbls)		Total (BOE)
Proved developed reserves:
December 31, 2020		10,688,857		12,992,674		2,029,392		14,883,695
December 31, 2021		11,197,370		15,350,678		2,207,738		15,963,554
December 31, 2022		12,959,918		16,547,639		2,355,866		18,073,724
Proved undeveloped reserves:
December 31, 2020		3,725,318		3,805,556		599,102		4,958,679
December 31, 2021		4,903,327		5,549,475		798,893		6,627,133
December 31, 2022		8,072,010		7,929,948		1,128,419		10,522,087

The following details the changes in proved undeveloped reserves (PUD) for 2021 and 2022:

	BOE
Proved undeveloped reserves, December 31, 2020		4,958,679
Revisions of previous estimates (1)		2,852,020
Extensions, discoveries and other additions (2)		2,006,163
Conversion to proved developed reserves (3)		(3,189,729	)
Proved undeveloped reserves acquired		-
Proved undeveloped reserves, December 31, 2021		6,627,133
Revisions of previous estimates (4)		7,803,541
Extensions, discoveries and other additions (5)		1,614,430
Conversion to proved developed reserves (6)		(5,523,017	)
Proved undeveloped reserves acquired		-
Proved undeveloped reserves, December 31, 2022		10,522,087

(1)	The annual review of the PUDs resulted in a positive revision of approximately 2,852 MBOE. This revision was the result of 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule and 94 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2021 to December 31, 2020.
(2)	In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(3)	The Partnership completed 23 new wells during 2021; therefore, the Partnership converted these 23 wells to proved developed reserves during 2021, which resulted in a downward adjustment to PUDs of 3,190 MBOE.
(4)	The annual review of the PUDs resulted in a positive revision of approximately 7,804 MBOE. This revision was the result of 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and offset by 373 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2022 to December 31, 2021.
(5)	In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(6)	The Partnership completed 27 new wells during 2022; therefore, the Partnership converted these 27 wells to proved developed reserves during 2022, which resulted in a downward adjustment to PUDs of 5,523 MBOE.

Based upon current information from its operators, the Partnership anticipates all current PUD locations will be drilled and converted to PDP within five years of the date they were added. PUD locations and associated reserves which are no longer projected to be drilled within five years from the date they were first booked as proved undeveloped reserves have been removed as revisions at the time that determination was made.

Standardized Measure of Discounted Future Net Cash Flows

Accounting standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Partnership has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year.

The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.

	2022			2021
Future cash inflows	$	2,209,148,928		$	1,125,263,104
Future production costs		(586,350,144	)		(365,741,504	)
Future development costs		(110,237,400	)		(63,988,780	)
Future net cash flows		1,512,561,384			695,532,820
10% annual discount		(864,351,720	)		(387,348,180	)
Standardized measure of discounted future net cash flows	$	648,209,664		$	308,184,640

Changes in the standardized measure of discounted future net cash flows are as follows:

	2022			2021
Standardized measure at beginning of period	$	308,184,640		$	72,886,760
Changes resulting from:
Acquisition of reserves		-			-
Extensions, discoveries and other additions		49,126,990			25,896,564
Sales of oil, natural gas and NGLs, net of production costs		(85,215,526	)		(56,778,262	)
Net changes in prices and production costs		240,520,851			167,970,653
Development costs incurred during the period		49,381,239			24,217,681
Revisions to previous estimates		150,980,130			96,257,622
Accretion of discount		30,861,199			7,298,783
Change in estimated future development costs		(95,629,859	)		(29,565,161	)
Standardized measure of discounted future net cash flows	$	648,209,664		$	308,184,640

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Accounting Policies, by Policy (Policies)

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

Basis of Presentation

The accompanying consolidated financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”). The consolidated financial statements include the accounts of the Partnership and its subsidiaries.

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash, Cash Equivalents and Restricted Cash and Cash Equivalents

Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.

Oil and Gas Properties Policy [Policy Text Block]

Property and Depreciation, Depletion and Amortization

The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of oil and natural gas properties are depleted using the unit-of-production method on a field basis based on estimated proved developed and/or undeveloped oil, natural gas and NGL reserves.

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]

Impairment

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (“SEC”), the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected NYMEX forward strip prices for oil, natural gas and NGL as estimated by management are used. Oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of oil, natural gas and NGL reserves used in formulating management’s overall operating decisions.

The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined.

Revenue [Policy Text Block]

Revenue Recognition

The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Oil, natural gas and natural gas liquids revenue receivable in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

Concentration Risk, Credit Risk, Policy [Policy Text Block]

Accounts Receivable and Concentration of Credit Risk

For the year ended December 31, 2022, the Partnership’s oil, natural gas and NGL sales were through two operators. Substantially all the Partnership’s accounts receivable is due from Chord, the largest operator of the Partnership’s oil and natural gas properties in North Dakota (operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2022, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. Chord is the current operator of 99% of the Partnership’s producing properties. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership.

Asset Retirement Obligation [Policy Text Block]

Asset Retirement Obligation

The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

The following table shows the activity for the years ended December 31, 2022 and 2021, relating to the Partnership’s asset retirement obligations:

Balance as of December 31, 2020	$	1,564,105
Well additions		139,343
Accretion		87,893
Revisions in estimated cash flows		-
Balance as of December 31, 2021		1,791,341
Well additions		95,480
Accretion		97,588
Revisions in estimated cash flows		(17,671	)
Balance as of December 31, 2022	$	1,966,738

Income Tax, Policy [Policy Text Block]

Income Tax

The Partnership is taxed as a partnership for federal and state income tax purposes. Typically, the Partnership has not recorded a provision for income taxes since the liability for such taxes is that of each of the partners rather than the Partnership. 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. Therefore, the Partnership has recorded an estimate of North Dakota tax withholding on behalf of these certain non-resident limited partners for the tax years of 2021 and 2022 of approximately $0.6 million. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners.

The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.

Environmental Costs, Policy [Policy Text Block]

Environmental Costs

As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved.

Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2022 and 2021, there were no such costs accrued.

Earnings Per Share, Policy [Policy Text Block]

Net Income Per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2022 and 2021. As a result, basic and diluted outstanding common units were the same. The Class B Units and Incentive Distribution Rights are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 7) would occur.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Schedule of Asset Retirement Obligations [Table Text Block]

The following table shows the activity for the years ended December 31, 2022 and 2021, relating to the Partnership’s asset retirement obligations:

Balance as of December 31, 2020	$	1,564,105
Well additions		139,343
Accretion		87,893
Revisions in estimated cash flows		-
Balance as of December 31, 2021		1,791,341
Well additions		95,480
Accretion		97,588
Revisions in estimated cash flows		(17,671	)
Balance as of December 31, 2022	$	1,966,738

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021.

	Fair Value Measurements at December 31, 2022
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(3,173,965	)	$	-
Total	$	-	$	(3,173,965	)	$	-

	Fair Value Measurements at December 31, 2021
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(1,264,935	)	$	-
Commodity derivatives - noncurrent liabilities	$	-	$	(1,099,388	)	$	-
Total	$	-	$	(2,364,323	)	$	-

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Risk Management (Tables)

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The Partnership did not designate its 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 the settlement losses of matured derivative instruments and non-cash mark-to-market losses for the periods presented.

	Year Ended December 31, 2022			Year Ended December 31, 2021
Settlements on matured derivatives	$	(6,603,660	)	$	(1,182,420	)
Loss on mark-to-market of derivatives, net		(668,714	)		(1,761,563	)
Loss on derivatives	$	(7,272,374	)	$	(2,943,983	)

Schedule of Derivative Instruments [Table Text Block]

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.

Settlement Period	Basis	Product	Volume	Weighted Average Floor / Ceiling Prices ($)
01/2023 - 09/2023	NYMEX	Oil (bbls)	224,000	50.00 / 69.72
02/2023 - 09/2023	Henry Hub	Gas (MMbtu)	275,000	2.00 / 4.30

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2022

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2022 and 2021 is as follows:

	2022			2021
Producing properties	$	296,175,283		$	246,974,543
Non-producing		176,389,110			176,208,611
		472,564,393			423,183,154
Accumulated depreciation, depletion and amortization		(119,045,055	)		(98,150,833	)
Net capitalized costs	$	353,519,338		$	325,032,321

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

For the years ended December 31, 2022 and 2021, the Partnership incurred the following costs in oil and natural gas producing activities:

	2022		2021
Development costs	$	49,381,239	$	24,217,681

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

The rollforward of net quantities of proved developed and undeveloped oil, natural gas and NGL reserves are summarized as follows:

	Proved Reserves
	Oil			Natural Gas			NGLs
	(Bbls)			(Mcf)			(Bbls)			Total (BOE)
December 31, 2020		14,414,175			16,798,230			2,628,494			19,842,374
Acquisition		-			-			-			-
Extensions, discoveries and other additions (1)		1,484,190			1,680,394			241,907			2,006,163
Revisions of previous estimates (2)		1,169,401			3,581,458			301,081			2,067,393
Production		(967,069	)		(1,159,929	)		(164,851	)		(1,325,243	)
December 31, 2021		16,100,697			20,900,153			3,006,631			22,590,687
Acquisition		-			-			-			-
Extensions, discoveries and other additions (3)		1,266,835			1,125,029			160,090			1,614,430
Revisions of previous estimates (4)		4,719,015			3,782,400			508,067			5,857,482
Production		(1,054,619	)		(1,329,995	)		(190,503	)		(1,466,788	)
December 31, 2022		21,031,928			24,477,587			3,484,285			28,595,811

(1)	In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(2)	Revisions to previous estimates increased proved reserves by a net amount of 2,067 MBOE. These revisions result from 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule, offset by 691 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020.
(3)	In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(4)	Revisions to previous estimates increased proved reserves by a net amount of 5,857 MBOE. These revisions result from 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and 164 MBOE of upward adjustments attributable caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021, offset by 2,484 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021.

	Oil		Natural Gas		NGLs
	(Bbls)		(Mcf)		(Bbls)		Total (BOE)
Proved developed reserves:
December 31, 2020		10,688,857		12,992,674		2,029,392		14,883,695
December 31, 2021		11,197,370		15,350,678		2,207,738		15,963,554
December 31, 2022		12,959,918		16,547,639		2,355,866		18,073,724
Proved undeveloped reserves:
December 31, 2020		3,725,318		3,805,556		599,102		4,958,679
December 31, 2021		4,903,327		5,549,475		798,893		6,627,133
December 31, 2022		8,072,010		7,929,948		1,128,419		10,522,087

	BOE
Proved undeveloped reserves, December 31, 2020		4,958,679
Revisions of previous estimates (1)		2,852,020
Extensions, discoveries and other additions (2)		2,006,163
Conversion to proved developed reserves (3)		(3,189,729	)
Proved undeveloped reserves acquired		-
Proved undeveloped reserves, December 31, 2021		6,627,133
Revisions of previous estimates (4)		7,803,541
Extensions, discoveries and other additions (5)		1,614,430
Conversion to proved developed reserves (6)		(5,523,017	)
Proved undeveloped reserves acquired		-
Proved undeveloped reserves, December 31, 2022		10,522,087

(1)	The annual review of the PUDs resulted in a positive revision of approximately 2,852 MBOE. This revision was the result of 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule and 94 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2021 to December 31, 2020.
(2)	In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(3)	The Partnership completed 23 new wells during 2021; therefore, the Partnership converted these 23 wells to proved developed reserves during 2021, which resulted in a downward adjustment to PUDs of 3,190 MBOE.
(4)	The annual review of the PUDs resulted in a positive revision of approximately 7,804 MBOE. This revision was the result of 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and offset by 373 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2022 to December 31, 2021.
(5)	In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.
(6)	The Partnership completed 27 new wells during 2022; therefore, the Partnership converted these 27 wells to proved developed reserves during 2022, which resulted in a downward adjustment to PUDs of 5,523 MBOE.

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.

	2022			2021
Future cash inflows	$	2,209,148,928		$	1,125,263,104
Future production costs		(586,350,144	)		(365,741,504	)
Future development costs		(110,237,400	)		(63,988,780	)
Future net cash flows		1,512,561,384			695,532,820
10% annual discount		(864,351,720	)		(387,348,180	)
Standardized measure of discounted future net cash flows	$	648,209,664		$	308,184,640

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]

Changes in the standardized measure of discounted future net cash flows are as follows:

	2022			2021
Standardized measure at beginning of period	$	308,184,640		$	72,886,760
Changes resulting from:
Acquisition of reserves		-			-
Extensions, discoveries and other additions		49,126,990			25,896,564
Sales of oil, natural gas and NGLs, net of production costs		(85,215,526	)		(56,778,262	)
Net changes in prices and production costs		240,520,851			167,970,653
Development costs incurred during the period		49,381,239			24,217,681
Revisions to previous estimates		150,980,130			96,257,622
Accretion of discount		30,861,199			7,298,783
Change in estimated future development costs		(95,629,859	)		(29,565,161	)
Standardized measure of discounted future net cash flows	$	648,209,664		$	308,184,640

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Partnership Organization (Details) shares in Millions			12 Months Ended		46 Months Ended
	Dec. 18, 2015	Jul. 09, 2013 USD ($)	Dec. 31, 2022	Dec. 31, 2020	Apr. 24, 2017 USD ($) shares
Partnership Organization (Details) [Line Items]
Limited Liability Company or Limited Partnership, Business, Formation State		Delaware
Partners' Capital Account, Contributions (in Dollars)		$ 1,000
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net	11.00%		24.00%
Oil, Productive Well, Number of Wells, Net			293
Non-operated Wells in the Process of Drilling [Member]
Partnership Organization (Details) [Line Items]
Oil and Gas, Present Activity, Well in Process of Drilling			6
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net				12.00%
Oil and Gas, Present Activity, Well in Process of Drilling				6
Best-Efforts Offering [Member]
Partnership Organization (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares) | shares					19.0
Proceeds from Issuance of Common Limited Partners Units (in Dollars)					$ 374,200,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units (in Dollars)					$ 349,600,000

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Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended		24 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2022
Summary of Significant Accounting Policies (Details) [Line Items]
Estimated State Tax Withholding For Limited Partners (in Dollars)	$ (315,000)	$ (250,000)	$ 600,000
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	0
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | Whiting Petroleum [Member]
Summary of Significant Accounting Policies (Details) [Line Items]
Concentration Risk, Percentage	99.00%

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Summary of Significant Accounting Policies (Details) - Schedule of Asset Retirement Obligations - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Asset Retirement Obligations Abstract
Balance	$ 1,791,341	$ 1,564,105
Well additions	95,480	139,343
Accretion	97,588	87,893
Revisions in estimated cash flows	(17,671)	0
Balance	$ 1,966,738	$ 1,791,341

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Oil and Gas Investments (Details)				1 Months Ended	12 Months Ended			60 Months Ended
	Mar. 31, 2017	Jan. 11, 2017 USD ($)	Dec. 18, 2015 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2022
Oil and Gas Investments (Details) [Line Items]
Wells in Various Stages of Drilling and Completion Process					6
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 119,000,000
Costs Incurred, Development Costs (in Dollars)					116,000,000
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					2
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 4,000,000
Non-operated Completed Wells [Member]
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number					27	23		80
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			11.00%		24.00%
Oil, Productive Well, Number of Wells, Net					293			293
Non-operated Wells in the Process of Drilling [Member]
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Present Activity, Well in Process of Drilling					6			6
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net							12.00%
Oil and Gas, Present Activity, Well in Process of Drilling							6
Acquisition No. 1 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred (in Dollars)			$ 159,600,000
Acquisition No. 2 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net		11.00%
Business Combination, Consideration Transferred (in Dollars)		$ 128,500,000
Acquisition No. 3 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net	10.50%
Business Combination, Consideration Transferred (in Dollars)				$ 52,400,000
Number of Producing Partnership Wells Acquired	82
Oil, Productive Well, Number of Wells, Net	216			216
Number of Future Development Partnership Locations Acquired	150
Gas and Oil Area Undeveloped, Net	253
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Wells Elected to Participate in Drilling								86

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Debt (Details) - USD ($)			1 Months Ended	12 Months Ended
	May 13, 2021	Nov. 21, 2017	Jan. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt (Details) [Line Items]
Long-Term Line of Credit				$ 22,600,000	$ 23,000,000
Repayments of Lines of Credit			$ 2,600,000	14,000,000	17,063,389
Line of Credit Facility, Fair Value of Amount Outstanding				$ 22,600,000	$ 23,000,000
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount	$ 60,000,000	$ 40,000,000
Debt Instrument, Maturity Date	Mar. 01, 2024	Jul. 31, 2021
Long-Term Debt, Percentage Bearing Variable Interest, Percentage Rate	4.25%			8.00%
Long-Term Line of Credit	$ 40,000,000			$ 22,600,000
Debt Instrument, Fee	origination fee of 0.50% of the Maximum Credit Amount, or $300,000, and is subject to an additional fee of 0.25% on any incremental increase to the borrowing base
Debt Issuance Costs, Gross	$ 400,000
Unamortized Debt Issuance Expense	166,000
Debt Issuance Costs, Noncurrent, Net	142,000
Debt Issuance Costs, Current, Net	$ 24,000
Line of Credit Facility, Commitment Fee Description	The Partnership also is required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the Revolving Credit Facility, based on borrowings outstanding during a quarter
Proceeds from Lines of Credit	$ 40,000,000
Repayments of Lines of Credit	$ 40,000,000
Line of Credit Facility, Collateral	The BF Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells
Line of Credit Facility, Borrowing Capacity, Description	Under the BF Loan Agreement, the initial borrowing base was $60 million. The Partnership’s borrowing base is reduced by a Monthly Commitment Reduction, which is currently stipulated to be $1 million. Therefore, as of December 31, 2022, the borrowing base was $41 million. The borrowing base and Monthly Commitment Reduction are subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. In conjunction with the Lender’s March 1 redetermination analysis, the Partnership and Lender agreed to amend the BF Loan Agreement, including establishing a fixed borrowing base of $30 million and eliminating the Monthly Commitment Reduction. See additional information in Note 9. Subsequent Events. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period
Line of Credit Facility, Covenant Compliance				The Partnership was in compliance with its applicable covenants at December 31, 2022.
Revolving Credit Facility [Member] | Prime Rate [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
Debt Instrument, Minimum Interest Rate	4.00%

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Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	$ 0	$ 0
Commodity derivatives - noncurrent liabilities		0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	(3,173,965)	(1,264,935)
Commodity derivatives - noncurrent liabilities		(1,099,388)
Total	(3,173,965)	(2,364,323)
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	0	0
Commodity derivatives - noncurrent liabilities		0
Total	$ 0	$ 0

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Risk Management (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Discussion of Price Risk Derivative Risk Management Policy	Debt, 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.
Derivative Liability	$ 3,200,000	$ 2,400,000
Derivative Liability, Current	$ 3,173,965	1,264,935
Derivative Liability, Noncurrent		$ 1,099,388

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Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Derivative Instruments In Statement Of Financial Position Fair Value Abstract
Settlements on matured derivatives, net	$ (6,603,660)	$ (1,182,420)
Loss on mark-to-market of derivatives, net	(668,714)	(1,761,563)
Loss on derivatives, net	$ (7,272,374)	$ (2,943,983)

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Risk Management (Details) - Schedule of Derivative Instruments - Price Risk Derivative [Member]	12 Months Ended
	Dec. 31, 2022 $ / bbl bbl
Costless Collar Agreements 1 [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	224,000
Floor Price	50
Ceiling Price	69.72
Costless Collar Agreements 3 [Member]
Derivative [Line Items]
Basis	Henry Hub
Product	Gas (MMbtu)
Volume | bbl	275,000
Floor Price	2
Ceiling Price	4.3

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Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions		1 Months Ended		12 Months Ended		46 Months Ended
	Jul. 09, 2013	Jan. 31, 2023	Dec. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Apr. 24, 2017
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Contributions	$ 1,000
Distributions to organizational limited partner	$ 990
Managing Dealer, Selling Commissions, Percentage				6.00%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds, Percentage				4.00%
Maximum Contingent Offering Costs, Selling Commissions and Marketing Expenses			$ 15,000,000	$ 15,000,000
Key Provisions of Operating or Partnership Agreement, Description				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:  ● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;   ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)			$ 0.138082	$ 1.258082	$ 0.189863
Distribution Made to Limited Partner, Cash Distributions Paid			$ 2,600,000	$ 23,870,186	$ 3,602,361
Repayments of Lines of Credit		$ 2,600,000		$ 14,000,000	$ 17,063,389
Annualized Rate Of Retun				7.00%
Distribution At Payout To Limited Partner Per Common Unit (in Dollars per share)				$ 2.387671
Distribution At Payout To Limited Partner				$ 45,000,000
Best-Efforts Offering [Member]
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares)						19.0
Proceeds from Issuance of Common Limited Partners Units						$ 374,200,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units						$ 349,600,000

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Related Parties (Details) - USD ($)				12 Months Ended
	Jan. 01, 2020	Apr. 06, 2017	Apr. 05, 2017	Dec. 31, 2022	Dec. 31, 2021	Mar. 31, 2017
Related Parties (Details) [Line Items]
Class B Units, Units Outstanding (in Shares)				62,500	62,500
E11 Incentive Holdings [Member]
Related Parties (Details) [Line Items]
Class B Units, Units Outstanding (in Shares)						62,500
Units transferred to E11 Incentive Carry Vehicle, LP for minimis Consideration [Member] | E11 Incentive Holdings [Member]
Related Parties (Details) [Line Items]
Class B Units, transferred (in Shares)			18,125
Units Sold to Regional Energy Incentives, LP [Member] | E11 Incentive Holdings [Member]
Related Parties (Details) [Line Items]
Class B Units, Units Sold (in Shares)		44,375
Class B Units, Total Sales Price for Sale of Capital Units		$ 98,000
General Partner [Member]
Related Parties (Details) [Line Items]
Selling, General and Administrative Expense				$ 165,000	$ 135,000
Other Liabilities, Current				57,000	44,000
Affiliated Entity [Member]
Related Parties (Details) [Line Items]
Selling, General and Administrative Expense				$ 634,000	$ 586,000
Administrative Service Agreement [Member]
Related Parties (Details) [Line Items]
Related Party, Administrative Service Agreement	Under the ASA, the Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick.

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Subsequent Events (Details) - Subsequent Event [Member] - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Mar. 31, 2023	Feb. 28, 2023	Jan. 31, 2023
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid			$ 2.6
Distribution Made to Limited Partner, Distributions Paid, Per Unit			$ 0.138082
Dividend Declared [Member]
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid		$ 2.3	$ 2.2
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.12	$ 0.117671
Revolving Credit Facility [Member]
Subsequent Events (Details) [Line Items]
Line of Credit Facility, Description	the Partnership and its Lender of the BF Credit Facility entered into an amendment to the BF Loan Agreement, resulting in the following changes effective as of the date of the amendment: (i) the borrowing base is fixed at $30 million; (ii) the Monthly Commitment Reduction, previously stipulated to be $1 million, has been eliminated; and (iii) the Restricted Payment Clause, which previously required the Partnership’s outstanding balance to be at or below 50% of the effective borrowing base to make distributions, has been eliminated

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details)	12 Months Ended				60 Months Ended
	Dec. 31, 2022 Boe $ / bbl $ / MMcf		Dec. 31, 2021 Boe $ / bbl $ / MMcf		Dec. 31, 2022
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	7,803,541	[1]	2,852,020	[2]
Number of Proved Developed Non-producing Wells Converted to Producing	27		23
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)	(5,523,017)	[3]	(3,189,729)	[4]
Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	5,857,000		(2,067,000)
Proved Reserves [Member] | Adjustment Related to Changes in Future Drill Schedule [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	8,177,000		(2,758,000)
Proved Reserves [Member] | Adjustments Related to Prices [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	164,000		(691,000)
Proved Reserves [Member] | Adjustments Related to Successful Drilling [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	1,614,000		2,006,000
Proved Reserves [Member] | Adjustments Related to Well Performance [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	(2,484,000)
Proved Undeveloped Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	7,804,000		2,852,000
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)			3,190,000
Proved Undeveloped Reserves [Member] | Adjustment Related to Changes in Future Drill Schedule [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)			2,758,000
Proved Undeveloped Reserves [Member] | Adjustments Related to Natural Gas Shrink [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	373,000		94,000
Non-operated Completed Wells [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number	27		23		80
Non-operated Completed Wells [Member] | Proved Undeveloped Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)	5,523,000
Including Effect of Price Differential Adjustments [Member] | Oil [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / bbl	90.51		60.08
Including Effect of Price Differential Adjustments [Member] | Natural Gas [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / MMcf	6.75		3.72
Including Effect of Price Differential Adjustments [Member] | Natural Gas Liquids [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / bbl	40.28		26.62

[1] The annual review of the PUDs resulted in a positive revision of approximately 7,804 MBOE. This revision was the result of 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and offset by 373 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2022 to December 31, 2021.

[2] The annual review of the PUDs resulted in a positive revision of approximately 2,852 MBOE. This revision was the result of 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule and 94 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2021 to December 31, 2020.

[3] The Partnership completed 27 new wells during 2022; therefore, the Partnership converted these 27 wells to proved developed reserves during 2022, which resulted in a downward adjustment to PUDs of 5,523 MBOE.

[4] The Partnership completed 23 new wells during 2021; therefore, the Partnership converted these 23 wells to proved developed reserves during 2021, which resulted in a downward adjustment to PUDs of 3,190 MBOE.

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved Properties	$ 472,564,393	$ 423,183,154
Accumulated depreciation, depletion and amortization	(119,045,055)	(98,150,833)
Net capitalized costs	353,519,338	325,032,321
Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved Properties	296,175,283	246,974,543
Non-Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved Properties	$ 176,389,110	$ 176,208,611

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cost Incurred In Oil And Gas Property Acquisition Exploration And Development Activities Disclosure Abstract
Development costs	$ 49,381,239	$ 24,217,681

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	12 Months Ended
	Dec. 31, 2022 Boe bbl Mcf		Dec. 31, 2021 Boe bbl Mcf		Dec. 31, 2020 Boe bbl Mcf
Reserve Quantities [Line Items]
Balance	22,590,687		19,842,374
Proved developed reserves:
Balance, Proved Developed Reserves (in Barrels of Oil Equivalent) | Boe	18,073,724		15,963,554		14,883,695
Proved undeveloped reserves:
Balance, Proved Undeveloped Reserves (in Barrels of Oil Equivalent) | Boe	10,522,087		6,627,133		4,958,679
Balance, Proved Undeveloped Reserves (in Barrels of Oil Equivalent) | Boe	10,522,087		6,627,133		4,958,679
Revisions of previous estimates (in Barrels of Oil Equivalent) | Boe	7,803,541	[1]	2,852,020	[2]
Extensions, discoveries and other additions (in Barrels of Oil Equivalent) | Boe	1,614,430	[3]	2,006,163	[4]
Conversion to proved developed reserves (in Barrels of Oil Equivalent) | Boe	(5,523,017)	[5]	(3,189,729)	[6]
Proved undeveloped reserves acquired (in Barrels of Oil Equivalent) | Boe	0		0
Acquisition	0		0
Extensions, discoveries and other additions	1,614,430	[7]	2,006,163	[8]
Revisions of previous estimates	5,857,482	[9]	2,067,393	[10]
Production	(1,466,788)		(1,325,243)
Balance	28,595,811		22,590,687
Oil [Member]
Reserve Quantities [Line Items]
Balance	16,100,697		14,414,175
Proved developed reserves:
Balance, Proved Developed Reserves	12,959,918		11,197,370		10,688,857
Proved undeveloped reserves:
Balance, Proved Undeveloped Reserves	8,072,010		4,903,327		3,725,318
Acquisition	0		0
Extensions, discoveries and other additions	1,266,835	[7]	1,484,190	[8]
Revisions of previous estimates	4,719,015	[9]	1,169,401	[10]
Production	(1,054,619)		(967,069)
Balance	21,031,928		16,100,697
Natural Gas [Member]
Reserve Quantities [Line Items]
Balance | Mcf	20,900,153		16,798,230
Proved developed reserves:
Balance, Proved Developed Reserves | Mcf	16,547,639		15,350,678		12,992,674
Proved undeveloped reserves:
Balance, Proved Undeveloped Reserves | Mcf	7,929,948		5,549,475		3,805,556
Acquisition | Mcf	0		0
Extensions, discoveries and other additions | Mcf	1,125,029	[7]	1,680,394	[8]
Revisions of previous estimates | Mcf	3,782,400	[9]	3,581,458	[10]
Production | Mcf	(1,329,995)		(1,159,929)
Balance | Mcf	24,477,587		20,900,153
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Balance	3,006,631		2,628,494
Proved developed reserves:
Balance, Proved Developed Reserves	2,355,866		2,207,738		2,029,392
Proved undeveloped reserves:
Balance, Proved Undeveloped Reserves	1,128,419		798,893		599,102
Acquisition	0		0
Extensions, discoveries and other additions	160,090	[7]	241,907	[8]
Revisions of previous estimates	508,067	[9]	301,081	[10]
Production	(190,503)		(164,851)
Balance	3,484,285		3,006,631

[1] The annual review of the PUDs resulted in a positive revision of approximately 7,804 MBOE. This revision was the result of 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and offset by 373 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2022 to December 31, 2021.

[2] The annual review of the PUDs resulted in a positive revision of approximately 2,852 MBOE. This revision was the result of 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule and 94 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2021 to December 31, 2020.

[3] In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.

[4] In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.

[5] The Partnership completed 27 new wells during 2022; therefore, the Partnership converted these 27 wells to proved developed reserves during 2022, which resulted in a downward adjustment to PUDs of 5,523 MBOE.

[6] The Partnership completed 23 new wells during 2021; therefore, the Partnership converted these 23 wells to proved developed reserves during 2021, which resulted in a downward adjustment to PUDs of 3,190 MBOE.

[7] In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.

[8] In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.

[9] Revisions to previous estimates increased proved reserves by a net amount of 5,857 MBOE. These revisions result from 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and 164 MBOE of upward adjustments attributable caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021, offset by 2,484 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021.

[10] Revisions to previous estimates increased proved reserves by a net amount of 2,067 MBOE. These revisions result from 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule, offset by 691 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020.

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure - USD ($)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure Abstract
Future cash inflows	$ 2,209,148,928	$ 1,125,263,104
Future production costs	(586,350,144)	(365,741,504)
Future development costs	(110,237,400)	(63,988,780)
Future net cash flows	1,512,561,384	695,532,820
10% annual discount	(864,351,720)	(387,348,180)
Standardized measure of discounted future net cash flows	$ 648,209,664	$ 308,184,640	$ 72,886,760

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure (Parentheticals)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Measurement Input, Discount Rate [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Annual discount	10.00%	10.00%

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Abstract
Standardized measure at beginning of period	$ 308,184,640	$ 72,886,760
Acquisition of reserves	0	0
Extensions, discoveries and other additions	49,126,990	25,896,564
Sales of oil, natural gas and NGLs, net of production costs	(85,215,526)	(56,778,262)
Net changes in prices and production costs	240,520,851	167,970,653
Development costs incurred during the period	49,381,239	24,217,681
Revisions to previous estimates	150,980,130	96,257,622
Accretion of discount	30,861,199	7,298,783
Change in estimated future development costs	(95,629,859)	(29,565,161)
Standardized measure of discounted future net cash flows	$ 648,209,664	$ 308,184,640