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, ~~2023~~2024

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

Commission File Number 000-55916

Energy Resources 12, L.P.

(Exact name of registrant as specified in its charter)

Delaware	~~81-4805237~~	81-4805237
(State or other jurisdiction of incorporation or organization)	~~(IRS Employer Identification No.)~~	(IRS Employer Identification No.)
120 W 3rd Street, Suite 220 Fort Worth, Texas	76102
(Address of principal executive offices)	(Zip Code)

120 W 3rd Street, Suite 220

Fort Worth, Texas

76102

(Address of principal executive offices)

(Zip Code)

(817) 882-9192

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Exchange 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 in 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, ~~2023~~2024 was $0.

As of March 1526, ~~2024~~2025, the Partnership had 11,031,579 common units outstanding.

Energy Resources 12, L.P.

Form 10-K

Index

		Page
Part I
	Item 1. Business	5
	Item 1A. Risk Factors	2119
	Item 1B. Unresolved Staff Comments	3633
	Item 1C. Cybersecurity	3633
	Item 2. Properties	3633
	Item 3. Legal Proceedings	3633
	Item 4. Mine Safety Disclosures	3633
Part II
	Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	3734
	Item 6. [Reserved]	4037
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	4037
	Item 7A. Quantitative and Qualitative Disclosures about Market Risk	4845
	Item 8. Financial Statements and Supplementary Data	4946
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	6665
	Item 9A. Controls and Procedures	6665
	Item 9B. Other Information	6665
	Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	6665
Part III
	Item 10. Directors, Executive Officers and Corporate Governance	6766
	Item 11. Executive Compensation	68
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	6968
	Item 13. Certain Relationships and Related Transactions, and Director Independence	70
	Item 14. Principal Accounting Fees and Services	7271
Part IV
	Item 15. Exhibits, Financial Statement Schedules	7372
	Item 16. Form 10-K Summary	7473
Signatures		7574

Index

Part I

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:

•● any impact of the ongoing ~~recovery~~Russian-Ukrainian ~~from~~and ~~COVID-19~~Middle Eastern conflicts on the global energy markets; •● intentions of the Partnership’s operators with regard to their drilling programs; •● 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 its 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 acquisitions and 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.

~~Item 1. Business~~4

~~Overview~~Index

Energy Resources 12, 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 $Item 1~~,000 occurred on December 30, 2016~~. The Partnership completed its best-efforts offering in October 2019 with a total of approximately 11.0 million common units sold for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.Business

As of December 31, 2023, the Partnership owned an approximate 5.6% non-operated working interest in 422 producing wells, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Partnership also owns an estimated approximate 5.5% non-operated working interest in 8 wells in various stages of the drilling and completion process, and possible future development locations in the Bakken Assets. The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 13 third-party operators on behalf of the Partnership and other working interest owners.Overview

Energy Resources 12, 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 ~~general~~initial ~~partner~~capitalization of the Partnership of is$1,000 ~~Energy~~occurred ~~Resources~~on 12December GP30, ~~LLC~~2016. ~~(the~~The ~~“General~~Partnership ~~Partner”)~~completed its best-efforts offering in October 2019 with a total of approximately 11.0 million common units sold for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

~~Business~~As of ~~Objective~~December 31, 2024, the Partnership owned an approximate 5.4% non-operated working interest in 447 producing wells, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”), and possible future development locations in the Bakken Assets. The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by third-party operators on behalf of the Partnership and other working interest owners.

The general ~~Partnership’s~~partner primary investment objectives are to (i) acquire producing and non-producing oil and gas properties with development potential to be operated by third-party operators on-shore in the United States, and to enhance the value of the ~~properties~~Partnership ~~through~~is ~~drilling~~Energy ~~and~~Resources ~~other~~12 ~~development activities~~GP, ~~(ii)~~LLC ~~make distributions to the holders of the common units,~~ (~~iii) engage in a liquidity transaction after five to seven years, in which all properties are sold and~~ the ~~sales~~“General ~~proceeds are distributed to the partners, merge with another entity, or list the common units on a national securities exchange, and (iv~~Partner”) ~~permit holders of common units to invest in oil and gas properties in a tax efficient basis~~. ~~The proceeds from the sale of the common units primarily have been used to acquire the Bakken Assets and to develop these assets.~~

~~Investment and Historical Drilling Activity~~Business Objective

The Partnership’s ~~acquired~~primary ~~its~~investment objectives are to (i) acquire producing and non-producing oil and natural gas properties with development potential to be operated ~~working~~by ~~interests~~third-party operators on-shore in the ~~Bakken~~United ~~Assets~~States, ~~during~~and ~~2018~~to inenhance ~~two~~the ~~transactions.~~value Onof ~~February~~the 1,properties ~~2018~~through drilling and other development activities, (ii) make distributions to the ~~Partnership~~holders ~~completed~~of ~~its~~the ~~first~~common ~~purchase~~units, (iii) engage in ~~the~~a ~~Bakken~~liquidity ~~Assets~~transaction ~~for~~after ~~$87.5~~five ~~million~~to seven years, ~~subject~~in towhich all ~~customary~~properties ~~adjustments.~~are Onsold ~~August~~and 31the sales proceeds are distributed to the partners, ~~2018~~merge with another entity, or list the ~~Partnership~~common ~~completed~~units ~~its~~on a ~~second~~national ~~purchase~~securities exchange, and (iv) permit holders of common units to invest in ~~the~~oil ~~Bakken~~and ~~Assets~~natural ~~for~~gas ~~$82~~properties in a tax efficient basis.5 ~~million,~~The ~~subject~~proceeds from the sale of the common units primarily have been used to ~~customary~~acquire ~~adjustments~~the Bakken Assets and to develop these assets.

From September 1, 2017, the effective date of the Partnership’s first acquisition, to December 31, 2023, the Partnership has participated in the drilling of 244 wells, of which 218 have been completed at December 31, 2023. The Partnership has incurred a total of approximately $82.5 million in capital drilling Investment and ~~completion~~Historical ~~costs~~Drilling ~~to develop these 244 wells through December 31, 2023. The Partnership anticipates less than $1 million of capital expenditures will be incurred to complete the 8 wells in process at December 31, 2023.~~Activity

~~Industry~~The Partnership ~~Operating~~acquired ~~Environment~~its non-operated working interests in the Bakken Assets during 2018 in two transactions. On February 1, 2018, the Partnership completed its first purchase in the Bakken Assets for $87.5 million, subject to customary adjustments. On August 31, 2018, the Partnership completed its second purchase in the Bakken Assets for $82.5 million, subject to customary adjustments.

~~The~~From September ~~oil~~1, ~~and~~2017, ~~natural~~the ~~gas~~effective ~~industry~~date isof ~~affected by many factors that~~ the Partnership’s ~~generally~~first ~~cannot control~~acquisition, ~~including~~to ~~the~~December ~~prices~~31, ~~of oil~~2024, ~~natural gas and natural gas liquids (“NGL”). Global macroeconomic factors contributing to uncertainty within~~ the ~~industry~~Partnership ~~include~~has ~~real or perceived geopolitical risks~~ participated in ~~oil-producing~~the ~~regions~~drilling of ~~the~~249 ~~world~~wells, ~~particularly~~of ~~the~~which ~~Middle~~244 ~~East~~have ~~and~~been ~~Russia;~~completed ~~current~~at ~~and/or~~December ~~future~~31, ~~government~~2024. ~~sanctions~~The ~~impacting~~Partnership ~~certain~~has ~~oil~~incurred ~~producing~~a ~~nations;~~total ~~forecasted levels~~ of ~~global~~approximately $82.5 ~~economic~~million ~~growth~~in ~~combined~~capital ~~with~~drilling ~~forecasted global supply; supply levels of oil~~ and ~~natural~~completion ~~gas~~costs ~~due~~ to ~~exploration~~develop ~~and~~these ~~development~~249 ~~activities~~wells inthrough ~~the~~December ~~United~~31, ~~States;~~2024. ~~global~~The ~~health~~Partnership ~~concerns;~~anticipates less ~~environmental~~than ~~and~~$1 ~~climate~~million ~~change regulation; actions taken by the Organization~~ of ~~Petroleum~~capital ~~Exporting~~expenditures ~~Countries;~~will ~~and~~be ~~the~~incurred ~~strength~~to ofcomplete the ~~U.S.~~3 ~~dollar~~wells in ~~international~~process ~~currency~~at ~~markets.~~December ~~Natural~~31, ~~gas prices vary in accordance with North American supply and demand and are also affected by imports and exports of NGL~~2024. ~~Weather also has a significant impact on demand for natural gas since it is a primary heating source in the United States.~~

5Industry Operating Environment

~~Index~~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; 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.

~~Commodity~~The length ~~prices strengthened throughout 2021, primarily driven by increased demand resulting from the initial recovery from the COVID-19 pandemic~~ and ~~production~~outcome ~~restraint by domestic and foreign operators. The start~~ of the military conflict between ~~Russia~~Ukraine and ~~Ukraine~~Russia inas ~~March~~well ~~2022~~as ~~(which~~continued ~~remains~~unrest ~~ongoing),~~in ~~related~~the ~~economic~~Middle ~~sanctions~~East ~~imposed~~are onhighly ~~Russia~~ unpredictable, and ~~additional production growth by OPEC~~ further ~~exacerbated~~escalation ~~supply~~of ~~shortages,~~these ~~causing~~conflicts ~~oil~~could ~~prices~~lead to ~~peak~~significant atmarket ~~over $120 per barrel during the second quarter of 2022. Persistent concerns about a recession~~ and ~~short-term~~other ~~softening~~disruptions, ofsuch ~~global~~as ~~and~~volatility ~~domestic~~in ~~demand contributed to lower~~ commodity prices and ~~during~~supply ~~the first half~~ of ~~2023.~~energy ~~Oil~~resources, ~~prices~~instability ~~rebounded to 12-month highs late~~ in ~~September~~financial ~~2023~~markets, atsupply ~~over~~chain ~~$90 per barrel~~interruptions, ~~primarily~~political ~~due~~and tosocial ~~Saudi~~instability ~~Arabia~~ and ~~Russia~~other material ~~continuing~~and ~~their~~adverse ~~commitments~~effects toon ~~production~~macroeconomic ~~cuts~~conditions. ~~However,~~The ashort- ~~surge~~and inlong-term ~~exports~~impact ~~from~~of ~~U.S.~~these ~~producers~~conflicts inon the ~~fourth~~operations ~~quarter~~and financial condition of ~~2023,~~the ~~along~~Partnership ~~with~~and ~~weakening~~the global ~~demand,~~economy ~~led~~is ~~to oil prices falling close to $70 per barrel by year end~~uncertain.

OnConsistent ~~October~~with 7,non-operators ~~2023,~~of ~~the~~well ~~conflict~~interests within ~~between~~the ~~Israel and Palestinian territories was reignited when Hamas~~industry, athe ~~militant~~Partnership ~~group~~engages in ~~control~~oil ofand ~~Gaza,~~natural ~~carried~~gas ~~out~~well adevelopment ~~surprise~~by ~~attack~~participating on ~~Israeli~~a ~~cities~~proportionate ~~and~~basis ~~towns~~alongside third-party ~~near~~interests ~~the~~in ~~Gaza~~wells ~~strip.~~drilled ~~Both~~and ~~sides~~completed ~~have been~~ in ~~constant~~spacing ~~combat~~units ~~since.~~that ~~The~~include ~~length and outcome of~~ the ~~military~~Partnership’s ~~conflicts~~acreage. ~~between~~The ~~Ukraine~~Partnership ~~and~~relies on ~~Russia~~its asoperators ~~well~~to aspropose, ~~Israel~~permit and ~~Hamas~~initiate ~~are~~the ~~highly~~drilling ~~unpredictable,~~of ~~and~~wells. ~~further~~The ~~escalation~~Partnership ofassesses ~~these~~each ~~conflicts~~drilling ~~could~~opportunity ~~lead~~on toa ~~significant~~case-by-case basis ~~market~~ and ~~other~~participates ~~disruptions, such as volatility~~ in ~~commodity~~wells ~~prices~~that ~~and~~expect ~~supply~~to ofmeet ~~energy~~a ~~resources,~~desired ~~instability~~return inbased ~~financial~~upon ~~markets,~~estimates ~~supply~~of ~~chain~~recoverable ~~interruptions,~~oil ~~political~~ and ~~social~~natural ~~instability~~gas, ~~and~~expected oil ~~other material~~ and ~~adverse~~natural ~~effects~~gas onprices, ~~macroeconomic~~expertise ~~conditions. The short- and long-term impact~~ of ~~these conflicts on~~ the ~~operations~~operator, and ~~financial~~completed ~~condition~~well ofcost ~~the~~from ~~Partnership~~each ~~and~~project, ~~the~~as ~~global~~well ~~economy~~as isother ~~uncertain~~factors.

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.5

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.Index

~~Production~~The Partnership’s operators generally market and sell the oil and natural gas extracted from Partnership wells. In addition, ~~Prices~~these operators coordinate the transportation of oil and ~~Production~~natural ~~Cost~~gas ~~History~~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.

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

	Year Ended December 31,				Percent
	2023		2022		Change
Sold production (BOE):
Oil		549,241		503,925		9.0	%
Natural gas		182,084		154,630		17.8	%
Natural gas liquids		168,906		141,495		19.4	%
Total		900,231		800,050		12.5	%
Average sales price per unit:
Oil (per Bbl)	$	77.13	$	94.00		-17.9	%
Natural gas (per Mcf)		2.52		6.45		-60.9	%
Natural gas liquids (per Bbl)		20.80		33.93		-38.7	%
Combined (per BOE)		54.02		72.68		-25.7	%
Average unit cost per BOE:
Production costs
Production expenses		22.66		20.46		10.8	%
Production taxes		4.57		5.87		-22.2	%
Total production costs		27.23		26.33		3.4	%
Depreciation, depletion, amortization and accretion		20.29		17.15		18.3	%

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
	2024		2023		Change

Sold production (BOE):
Oil		421,815		549,241		-23.2	%
Natural gas		176,373		182,084		-3.1	%
Natural gas liquids		156,667		168,906		-7.2	%
Total		754,855		900,231		-16.1	%

Average sales price per unit:
Oil (per Bbl)	$	74.02	$	77.13		-4.0	%
Natural gas (per Mcf)		1.45		2.52		-42.5	%
Natural gas liquids (per Bbl)		21.45		20.80		3.1	%
Combined (per BOE)		47.85		54.02		-11.4	%

Average unit cost per BOE:
Production costs
Production expenses		23.41		22.66		3.3	%
Production taxes		3.87		4.57		-15.3	%
Total production costs		27.28		27.23		0.2	%
Depreciation, depletion, amortization and accretion		23.61		20.29		16.3	%

~~Index~~Related Parties

~~Related~~The Partnership ~~Parties~~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.

~~The~~See further ~~Partnership~~discussion ~~has, and is expected to continue to engage~~ in, ~~significant~~Note ~~transactions with related parties~~6. ~~These~~Related ~~transactions~~Parties ~~cannot~~in bePart ~~construed~~II, toItem be8 ~~at arm’s length and the results~~ of ~~the~~this ~~Partnership’s~~Form ~~operations may be different than if conducted with non~~10-~~related parties~~K. 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~~Partners’ Equity ~~further~~and ~~discussion in Note 5. Related Parties in Part II, Item 8 of this Form 10-K.~~Distributions

~~Partners~~The Partnership completed its best-efforts offering of common units on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million. David Lerner Associates, Inc. was the dealer manager for the Partnership’s ~~Equity~~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 ~~Distributions~~marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager also has Dealer Manager Incentive Fees (defined below), where the Dealer Manager could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering based on the performance of the Partnership. Based on the common units sold in the offering, the Dealer Manager Incentive Fees are a maximum of approximately $8.7 million, subject to Payout (defined below).

~~The~~Prior ~~Partnership~~to ~~completed~~“Payout,” ~~its~~which ~~best-efforts~~is ~~offering of common units on October 24~~defined below, ~~2019.~~all As of the ~~conclusion~~distributions ofmade ~~the~~by ~~offering,~~ the Partnership, ~~had~~if ~~completed~~any, ~~the~~will ~~sale~~be ofpaid ~~approximately~~to ~~11.0~~the ~~million~~holders of common units ~~for total gross proceeds of $218~~.0 ~~million and proceeds net of offering costs of $204.3 million. David Lerner Associates~~Accordingly, ~~Inc. was~~ the ~~dealer manager for the~~ Partnership’s will ~~best-efforts~~not ~~offering~~make ~~(the~~any ~~“Dealer~~distributions ~~Manager”). Under the agreement~~ with ~~the~~respect ~~Dealer~~to ~~Manager,~~ the ~~Dealer~~Incentive ~~Manager~~Distribution ~~received~~Rights ~~a total of 6% in selling commissions~~ and ~~marketing~~will ~~expense~~not ~~allowance~~pay ~~based on gross proceeds of~~ the ~~common units sold. The~~ Dealer Manager ~~also has Dealer Manager~~ Incentive Fees ~~(defined below), where the Managing Dealer could receive distributions up~~ to ~~an additional 4% of gross proceeds of~~ the ~~common units sold in the Partnership’s best-efforts offering based on the performance of the Partnership. Based on the common units sold in the offering, the~~ Dealer Manager ~~Incentive Fees are a maximum of approximately $8.7 million~~, ~~subject~~until to Payout ~~(defined below)~~occurs.

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 and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.6

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.Index

InThe Partnership ~~June~~Agreement ~~2023,~~provides ~~the~~that ~~General~~“Payout” ~~Partner~~occurs ~~declared~~on ~~and~~the ~~paid~~day awhen ~~special~~the ~~distribution~~aggregate toamount ~~return~~distributed ~~$1.60~~with ~~per~~respect ~~common unit of capital~~ to ~~holders~~ each of ~~Partnership~~the common units. Inequals ~~addition,~~$20.00 inplus ~~May~~the ~~2023,~~Payout ~~the~~Accrual. The Partnership ~~paid~~Agreement adefines ~~withholding~~“Payout ~~tax~~Accrual” ofas ~~approximately~~7% ~~$0.03~~ per ~~common~~annum simple ~~unit~~interest toaccrued monthly until paid on the ~~state~~Net ofInvestment ~~North~~Amount ~~Dakota~~outstanding onfrom ~~behalf~~time ofto ~~its~~time. ~~limited~~The ~~partners~~Partnership ~~related~~Agreement todefines Net ~~tax~~Investment ~~year~~Amount ~~2021.~~initially ~~This~~as ~~withholding~~$20.00 ~~tax~~per ~~payment~~common unit, ~~along~~regardless ~~with~~of the ~~$1.60~~amount ~~per~~paid for the common unit. ~~special~~If ~~distribution~~at any time the Partnership distributes to holders of ~~its~~ common units inmore ~~June~~than ~~2023,~~the ~~has~~Payout ~~reduced~~Accrual, the ~~Net~~amount ~~Investment~~the ~~Amount~~Partnership ~~described~~distributes ~~above~~in byexcess anof ~~approximate~~the ~~total~~Payout ofAccrual will ~~$1.63~~reduce ~~per~~the ~~common~~Net ~~unit~~Investment Amount.

~~All~~In June ~~distributions~~2023, ~~made~~the byGeneral ~~the~~Partner declared and paid a special distribution to return $1.60 per common unit of capital to holders of Partnership common ~~after~~units. ~~Payout,~~As ~~which~~described ~~may~~in ~~include~~Income ~~all~~Tax orin aNote ~~portion~~2. Summary of ~~the~~Significant ~~proceeds~~Accounting Policies in Part II, Item 8 of this Form 10-K, in May 2023 and April 2024, the ~~sale~~Partnership paid total withholding taxes of ~~all~~approximately or$0.09 ~~substantially~~per ~~all~~common unit to the state of North Dakota on behalf of its limited partners related to tax years 2021, 2022 and 2023. These withholding tax payments, along with the $1.60 ~~Partnership’s~~per ~~assets~~common unit special distribution to holders of its common units in June 2023, ~~will~~have bereduced ~~made~~the asNet ~~follows:~~Investment Amount described above by an approximate total of $1.69 per common unit.

●All distributions ~~First,~~made ~~(i)~~by to the ~~Record~~Partnership ~~Holders~~after ~~of the Incentive Distribution Rights~~Payout, ~~30%;~~which ~~(ii)~~may toinclude ~~the~~all ~~Managing~~or ~~Dealer,~~a ~~the~~portion ~~“Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4%~~ of the ~~gross~~ proceeds of the ~~common~~sale ~~units~~of ~~sold;~~all ~~and~~or ~~(iii)~~substantially all toof the ~~Record~~Partnership’s ~~Holders of outstanding common units~~assets, ~~40%,~~will ~~pro~~be ~~rata~~made ~~based~~as ~~on their percentage interest.~~follows:

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

	●	First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Dealer Manager, the “Dealer Manager Incentive Fees”, 30%, until such time as the Dealer Manager receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.
	●	Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

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.

For the year ended December 31, ~~2023~~2024, the Partnership declared and paid distributions of $21.~~939163~~282163 per common unit, or $3214.41 million. For the year ended December 31, ~~2022~~2023, the Partnership declared and paid distributions of $12.~~396164~~939163 per common unit, or $1532.4 million.

7Oil and Natural Gas Reserves

~~Index~~The table below summarizes the Partnership’s estimated net proved reserves as of December 31, 2024:

Oil and Natural Gas Reserves

	Oil		Natural Gas		NGLs		Total		Standardized Measure (2)
Proved Reserves (1)	(MBbls)		(MMcf)		(MBbls)		(MBOE)		(in thousands)
PDP Properties		2,835		5,437		865		4,606	$	44,464
PUD Properties		3,238		2,274		439		4,056		36,384
Total Proved Reserves		6,073		7,711		1,304		8,662	$	80,848

(1) The ~~table~~following ~~below~~terms ~~summarizes~~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 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 ~~estimated~~proved ~~net~~reserves ~~proved~~as of December 31, 2024 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, ~~2023:~~2024 were $75.33 per barrel of oil, $1.43 per MMcf of natural gas and $0.49 per barrel of NGL. See “Note 8 — 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.

	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBOE)		Standardized Measure (2)
Proved Reserves (1)									(in thousands)
PDP Properties		3,454		6,170		893		5,376	$	67,869
PUD Properties		2,711		1,938		288		3,322		37,408
Total Proved Reserves		6,165		8,108		1,181		8,698	$	105,277

(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 natural 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.

(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 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, 2023 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, 2023 were $78.53 per barrel of oil, $2.81 per MMcf of natural gas and $2.29 per barrel of NGL. See “Note 7 — 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.Index

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, ~~2023~~2024 were below the ~~2023~~2024 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.

8Proved Undeveloped Reserves (PUD)

~~Index~~At December 31, 2024, the Partnership had PUDs of approximately 4,056 BOE, or approximately 47% of total proved reserves. The following table reflects the changes in PUDs during 2024:

Proved Undeveloped Reserves (PUD)

	BOE
Proved undeveloped reserves, December 31, 2023		3,322,029
Revisions of previous estimates (1)		1,266,821
Extensions, discoveries and other additions		-
Conversion to proved developed reserves (2)		(532,465	)
Proved undeveloped reserves, December 31, 2024		4,056,385

At(1) ~~December~~The ~~31,~~annual ~~2023,~~review of the ~~Partnership~~PUDs ~~had~~resulted ~~PUDs~~in a positive revision of approximately 31,~~322~~267 ~~BOE,~~MBOE. orThis ~~approximately~~revision ~~38%~~was the result of ~~total~~1,177 ~~proved~~MBOE ~~reserves.~~of ~~The~~positive ~~following~~adjustments ~~table~~attributable ~~reflects~~to changes in the future drill schedule and 90 MBOE of positive adjustments attributable to changes in ~~PUDs~~natural ~~during~~gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2024 to December 31, 2023:.

	BOE
Proved undeveloped reserves, December 31, 2022		4,714,558
Revisions of previous estimates (1)		(1,052,598	)
Extensions, discoveries and other additions (2)		20,295
Conversion to proved developed reserves (3)		(360,226	)
Proved undeveloped reserves, December 31, 2023		3,322,029

(2)

The Partnership completed 26 new wells during 2024; therefore, the Partnership converted these 26 wells to proved developed reserves during 2024, which resulted in a downward adjustment to PUDs of 532 MBOE.

	(1)		The annual review of the PUDs resulted in a negative revision of approximately 1,053 MBOE. This revision was the result of 1,009 MBOE of downward adjustments attributable to changes in the future drill schedule, 43 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield, and 1 MBOE of downward adjustments attributable to price changes when comparing the Partnership’s reserves at December 31, 2023 to December 31, 2022.
	(2)		In 2023, extensions, discoveries and other additions of 20 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Bakken Assets.
	(3)		The Partnership completed 19 new wells during 2023; therefore, the Partnership converted these 19 wells to proved developed reserves during 2023, which resulted in a downward adjustment to PUDs of 360 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. All of the Partnership’s PUDs at December 31, 2024 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 geopolitical risks in oil producing regions of the world as well as global supply and demand concerns, 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.

~~Under~~Internal Controls ~~current~~Over ~~SEC~~Reserve ~~requirements,~~Estimates 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. All of the Partnership’s PUDs at December 31, 2023 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~~Qualifications ~~gas properties, it is difficult to predict with certainty the timing~~ of ~~drilling~~Technical and completion of wells currently classified as PUD reserves. Historically, energy commodity prices have been volatile, and due to geopolitical risks in oil producing regions of the world as well as global supply and demand concerns, 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.Persons

~~Internal~~The ~~Controls~~Partnership’s ~~Over~~policies ~~Reserve~~and ~~Estimates~~practices regarding internal controls over the recording of reserves is structured to objectively and ~~Qualifications~~accurately estimate its oil and natural 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 ~~Technical~~Petroleum ~~Persons~~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, 2024 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 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, 2023 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.8

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.Index

9The 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.

~~Index~~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 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 Partnership management to discuss matters and policies related to the Partnership’s reserves.

The Partnership’s ~~management~~methodologies ~~works~~include ~~closely~~reviews ~~with~~of ~~Pinnacle~~production ~~Energy~~trends, analogy to ~~ensure~~comparable ~~the integrity~~properties, ~~accuracy~~ and/or ~~timeliness~~volumetric ofanalysis. Performance ~~data~~methods ~~that~~are ispreferred. ~~furnished~~Reserve toestimates ~~them~~ for ~~their~~proved ~~reserve~~undeveloped ~~estimation process as well as to review~~ properties ~~and~~are ~~discuss~~based ~~the~~primarily ~~methods~~on ~~and~~volumetric ~~assumptions~~analysis ~~used~~or analogy byto ~~Pinnacle~~offset ~~Energy~~production in ~~their preparation of~~ the ~~year-end~~same ~~reserve~~or ~~estimates~~similar fields. The Partnership ~~also~~applies ~~reviews the methods~~ and ~~assumptions~~maintains ~~used~~internal bycontrols, ~~Pinnacle~~including ~~Energy~~but innot limited ~~the~~to ~~preparation of year-end reserve estimates and assesses them for reasonableness. The Board of Directors of~~ the ~~General~~following, ~~Partner also meets with Partnership management~~ to ~~discuss~~ensure ~~matters and policies related to~~ the ~~Partnership’s~~reliability of reserves. estimations:

~~The~~● ~~Partnership~~no employee’s ~~methodologies~~compensation ~~include~~is ~~reviews~~tied ofto ~~production~~the ~~trends,~~amount ~~analogy~~of toreserves ~~comparable~~booked; ~~properties,~~● ~~and/or~~the ~~volumetric~~Partnership ~~analysis.~~follows ~~Performance~~comprehensive ~~methods~~SEC-compliant ~~are~~internal ~~preferred.~~policies ~~Reserve~~to ~~estimates~~determine ~~for~~and report proved ~~undeveloped~~reserves; ~~properties~~● reserve estimates are ~~based~~made ~~primarily~~by onexperienced ~~volumetric~~reservoir ~~analysis~~engineers or ~~analogy~~under totheir ~~offset~~direct ~~production~~supervision; in● annual review by the ~~same~~Board orof ~~similar~~Directors ~~fields.~~of ~~The~~the General Partner of the Partnership’s ~~applies~~year-end ~~and~~reserve ~~maintains~~estimates ~~internal~~prepared ~~controls,~~by ~~including~~Pinnacle ~~but~~Energy; ~~not~~and ~~limited~~● tosemi-annually, the ~~following,~~Board toof ~~ensure~~Directors of the ~~reliability~~General ofPartner reviews all significant reserves ~~estimations:~~changes and all new proved undeveloped reserves additions.

●Total Productive 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.Wells

~~Total~~The following ~~Productive~~table ~~Wells~~sets forth information with respect to the Partnership’s ownership interest in productive wells as of December 31, 2024:

The following table sets forth information with respect to the Partnership’s ownership interest in productive wells as of December 31, 2023:

	December 31, 2024
	Gross		Net
Oil wells:
Williston Basin, North Dakota		449		24.6

	December 31, 2023
	Gross		Net
Oil wells:
Williston Basin, North Dakota		423		24.0

Of the total well count for 2024, none are multiple completions.

OfProductive wells are producing wells and wells the ~~total~~Partnership ~~well~~deems ~~count~~mechanically capable of production, including shut-in wells, wells waiting for ~~2022~~completion, ~~none~~plus wells that are ~~multiple~~drilled/cased ~~completions~~and completed, but waiting for pipeline hook-up. At December 31, 2024, the Partnership had 447 wells producing or capable of production and two shut-in wells. A gross well is a well in which we own a working interest. The number of net wells represents the sum of fractional working interests the Partnership owns in gross wells.

~~Productive wells are producing wells~~ Developed and ~~wells~~Undeveloped ~~the~~Acreage 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, 2023, the Partnership had 422 wells producing or capable of production and one shut-in well. A gross well is a well in which we own a working interest. The number of net wells represents the sum of fractional working interests the Partnership owns in gross wells.Position

~~Developed~~The following table sets forth information with respect to the Partnership’s gross and ~~Undeveloped~~net ~~Acreage~~developed ~~Position~~and undeveloped oil and natural gas acreage under lease as of December 31, 2024, all of which is located in the State of North Dakota in the United States:

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, 2023, 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

Williston Basin, North Dakota

7,037

2,950

1,489

624

8,526

3,574

Acreage allocated to developed properties

Acreage allocated to undeveloped wellsites

Total Acres

Gross

Net

Gross

Net

Gross

Net

Williston Basin, North Dakota

7,332

3,074

1,193

500

8,525

3,574

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.

10Index

~~Index~~Undeveloped Acreage Expirations

~~Undeveloped~~The Partnership ~~Acreage~~has ~~Expirations~~no undeveloped acreage expirations as all acreage is held by production.

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

~~Delivery~~As of ~~Commitments~~December 31, 2024, the Partnership had no commitments to deliver a fixed quantity of oil or natural gas.

AsMarketing and ~~of December 31, 2023, the Partnership had no commitments to deliver a fixed quantity of oil or natural gas.~~Customers

~~Marketing~~The market for the Partnership’s oil and ~~Customers~~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.

The ~~market for the~~ Partnership’s ~~oil~~properties ~~and~~are ~~natural~~operated ~~gas~~by ~~production~~third-party ~~depends~~operators, onwho ~~factors~~market ~~beyond~~and ~~its~~sell ~~control, including~~ the ~~extent~~Partnership’s ~~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~~liquids ~~marketing~~on behalf of ~~competitive fuels and~~ the ~~effect~~Partnership ~~of state~~ (and ~~federal regulation. The oil and natural gas industry also competes with~~ other ~~industries~~fractional inworking ~~supplying~~interest ~~the energy and fuel requirements of industrial, commercial and individual consumers~~owners).

~~The~~Title to Partnership’s properties are operated by 13 third-party operators, who market and sell the Partnership’s production of oil, natural gas and natural gas liquids on behalf of the Partnership (and other fractional working interest owners).Properties

~~Title~~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 ~~Properties~~all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and natural 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 natural 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.

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

~~Insurance~~Since the Partnership is not the operator of any of its properties, the Partnership primarily relies on the insurance of the operator(s) 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.

~~Since~~The ~~the~~ Partnership isre-evaluates ~~not~~ the ~~operator~~purchase of ~~any~~insurance, coverage oflimits ~~its~~and ~~properties,~~deductibles ~~the~~annually. ~~Partnership~~Future ~~primarily~~insurance ~~relies~~coverage onfor the ~~insurance~~oil ofand ~~the~~natural ~~operator(s)~~gas ofindustry ~~its~~could ~~properties,~~increase ofin ~~which~~cost ~~the~~and ~~Partnership’s~~may include ~~share~~higher ofdeductibles ~~the~~or ~~cost~~retentions. isIn ~~allocated~~addition, ~~back~~some toforms ~~the~~of ~~Partnership~~insurance ~~through~~may become unavailable in the ~~Joint~~future ~~Operating~~or ~~Agreement.~~unavailable ~~The~~on terms ~~Partnership’s~~that ~~operators~~are ~~have~~economically ~~insurance~~acceptable. ~~policies~~No assurance can be given that ~~include~~the ~~coverage~~Partnership ~~for~~will ~~general~~be ~~liability~~able ~~(includes~~to ~~sudden~~maintain ~~and~~insurance ~~accidental~~in ~~pollution),~~the ~~physical~~future at ~~damage~~rates tothat ~~its~~the ~~oil~~Partnership ~~and~~considers ~~gas~~reasonable ~~properties,~~and ~~control~~the ofPartnership ~~well,~~may ~~auto~~elect ~~liability,~~to ~~marine~~self-insure ~~liability,~~or ~~worker’s~~maintain ~~compensation~~only ~~and~~catastrophic ~~employer’s~~coverage for ~~liability,~~certain ~~among~~risks ~~other~~in ~~things~~the future.

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

~~Competition~~The oil and natural gas industry is highly competitive. The Partnership will encounter strong competition from independent oil and natural gas companies, master limited partnerships and from major oil and natural 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 the Partnership’s.

The Partnership ~~oil~~also ~~and~~may ~~natural~~be ~~gas~~affected ~~industry~~by iscompetition ~~highly~~for ~~competitive.~~drilling ~~The~~rigs, ~~Partnership~~human ~~will~~resources ~~encounter~~and ~~strong~~the ~~competition~~availability ~~from~~of ~~independent~~related equipment. In the past, the oil and natural gas ~~companies,~~industry ~~master~~has ~~limited~~experienced ~~partnerships~~shortages ~~and~~of ~~from~~drilling ~~major~~rigs, ~~oil~~equipment, pipe and ~~gas~~personnel, ~~companies~~which inhave ~~contracting~~delayed development ~~for~~ drilling ~~equipment~~ and ~~arranging~~other ~~the~~exploitation ~~services~~activities ofand ~~trained~~have ~~personnel~~caused significant price increases. ~~Many~~The ofPartnership ~~these~~is ~~competitors~~unable ~~have~~to ~~financial~~predict when, ~~and~~or ~~technical~~if, ~~resources~~such ~~and~~shortages ~~staffs~~may ~~substantially~~occur ~~larger~~or ~~than~~how they would affect the Partnership’s development and exploitation program.

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.10

11Index

~~Index~~Seasonal Nature of Business

Seasonal weather ~~Nature~~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 ~~Business~~their anticipated winter natural gas requirements during off–peak months. This can lessen seasonal demand fluctuations.

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 equipmentEnvironmental, Health ~~supplies~~ and ~~personnel~~Safety ~~during~~Matters ~~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.Regulation

~~Environmental~~The Partnership’s operations are subject to stringent and complex federal, ~~Health~~state and ~~Safety~~local ~~Matters~~laws and ~~Regulation~~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:

~~The~~● 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; ~~are~~● ~~subject~~restrict tothe ~~stringent~~types, quantities and ~~complex~~concentrations ~~federal~~of various substances that can be released into the environment or used in connection with drilling, ~~state~~production and ~~local~~transportation ~~laws~~activities; ~~and~~● ~~regulations~~limit ~~that~~or ~~govern~~prohibit ~~the~~drilling ~~oil~~activities ~~and~~on ~~natural~~lands ~~gas~~lying ~~industry~~within wilderness, aswetlands ~~well~~and asother ~~regulations~~protected ~~that~~areas; ~~protect~~● ~~the~~require ~~environment~~remedial measures to mitigate or remediate pollution from ~~the~~former ~~discharge~~and ongoing operations, and may also require site restoration, pit closure and plugging of ~~materials~~abandoned ~~into~~wells; and ● require the ~~environment.~~expenditure ~~These~~of ~~laws~~significant ~~and~~amounts ~~regulations~~in ~~may,~~connection ~~among~~with ~~other~~worker ~~things:~~health and safety.

●These laws, ~~require~~rules ~~the~~and ~~acquisition~~regulations ofmay ~~various~~also ~~permits~~restrict ~~before~~the ~~drilling~~rate ~~commences;~~of ●oil ~~require~~and ~~the~~natural ~~installation~~gas ofproduction ~~pollution~~below ~~control~~the ~~equipment~~rate inthat ~~connection~~would ~~with~~otherwise ~~operations;~~be ●possible. The ~~place~~regulatory ~~restrictions~~burden oron ~~regulations~~the ~~upon~~oil ~~the~~and ~~use~~natural orgas ~~disposal~~industry ofincreases the ~~material~~cost ~~utilized~~of doing business in the ~~Partnership’s~~industry ~~operations;~~and ●consequently ~~restrict~~affects profitability. ~~the types~~Additionally, ~~quantities~~Congress and ~~concentrations~~federal, ofstate ~~various~~and ~~substances~~local ~~that~~agencies ~~can~~frequently berevise ~~released~~environmental ~~into~~laws ~~the~~and ~~environment~~regulations, orand such ~~used~~changes incould ~~connection~~result ~~with~~in ~~drilling,~~increased ~~production~~costs ~~and~~for ~~transportation~~environmental ~~activities;~~compliance, ●such ~~limit~~as orwaste ~~prohibit~~handling, ~~drilling~~permitting, ~~activities~~or oncleanup ~~lands~~for ~~lying~~the ~~within~~oil and ~~wilderness,~~natural ~~wetlands~~gas industry and ~~other~~could ~~protected~~have ~~areas;~~a ●significant ~~require~~impact ~~remedial~~on ~~measures~~the toPartnership’s ~~mitigate~~operating orcosts. ~~remediate~~In ~~pollution~~general, ~~from~~the ~~former~~oil and ~~ongoing~~natural gas ~~operations,~~industry ~~and~~has ~~may~~been ~~also~~the ~~require~~subject ~~site~~of ~~restoration,~~increased ~~pit~~legislation ~~closure~~ and ~~plugging~~regulatory ofattention ~~abandoned~~with ~~wells;~~respect ~~and~~to ●environmental ~~require~~matters. ~~the~~The ~~expenditure~~ trend of ~~significant~~more ~~amounts~~expansive inand ~~connection~~stricter ~~with~~environmental ~~worker~~regulation ~~health~~may ~~and~~continue ~~safety~~for the long term.

~~These~~The following ~~laws,~~is ~~rules~~a ~~and~~summary ~~regulations may also restrict the rate~~ of ~~oil~~some ~~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~~existing ~~and consequently affects profitability. Additionally~~laws, ~~Congress~~rules and ~~federal, state and local agencies frequently revise environmental laws and~~ regulations, ~~and~~to ~~such~~which ~~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~~business ~~costs.~~operations Inare ~~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~~ Solid and ~~regulations~~Hazardous toWaste ~~which the Partnership’s business operations are subject.~~Handling

~~Solid~~The federal Resource Conservation and ~~Hazardous~~Recovery ~~Waste~~Act, ~~Handling~~or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous 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.

~~The~~Comprehensive Environmental ~~federal Resource Conservation and Recovery Act~~Response, orCompensation ~~RCRA,~~ and ~~comparable~~Liability state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous 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.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 statutes.

~~The~~Although CERCLA ~~Comprehensive~~generally ~~Environmental~~exempts ~~Response,~~“petroleum” ~~Compensation~~from ~~and~~the ~~Liability~~definition ~~Act,~~of orhazardous ~~CERCLA~~substance, ~~imposes~~in ~~strict,~~the ~~joint~~course ~~and~~of ~~several~~the ~~liability~~Partnership’s operators’ ~~for~~expected ~~costs~~operations, ofthe ~~investigation~~operators ~~and~~will ~~remediation~~generate ~~and~~wastes ~~for~~that ~~natural~~may ~~resource~~fall ~~damages~~within ~~without~~CERCLA’s ~~regard~~definition toof ~~fault~~hazardous substance orand ~~legality~~may dispose of ~~the~~these ~~original~~wastes ~~conduct,~~at ondisposal ~~certain~~sites ~~classes~~owned ofand ~~persons~~operated ~~with~~by ~~respect~~others. toComparable ~~the~~state ~~release~~statutes ~~into~~may ~~the~~not ~~environment~~provide ofa comparable ~~substances~~exemption ~~designated~~for ~~under~~petroleum, ~~CERCLA~~and asthere ~~hazardous~~is ~~substances.~~no ~~These~~guarantee ~~classes~~that offederal ~~persons,~~law orwill ~~so-called~~not ~~potentially~~adopt ~~responsible~~more ~~parties,~~stringent orrequirements ~~PRPs,~~with ~~include~~respect to the ~~current~~petroleum ~~and~~substances. ~~past~~The ~~owners~~Partnership ormay ~~operators~~also ofbe ~~a site where~~ the ~~release~~owner ~~occurred~~of ~~and~~sites ~~anyone~~on ~~who~~which ~~disposed~~hazardous orsubstances ~~arranged~~have ~~for~~been ~~the~~released. ~~disposal~~If ofcontamination is adiscovered ~~hazardous substance found~~ at ~~the~~a site. ~~CERCLA~~on ~~also~~which ~~authorizes~~ the ~~EPA~~Partnership ~~and,~~is inor ~~some~~has ~~instances,~~been ~~third~~an ~~parties~~owner or to ~~take~~which ~~actions~~the inPartnership ~~response~~sent tohazardous ~~threats~~substances, tothe ~~public~~Partnership could ~~health~~be orliable for the ~~environment~~costs ~~and~~of toinvestigation ~~seek~~and toremediation ~~recover~~and ~~from~~natural ~~the~~resources ~~PRPs~~damages. Further, the ~~costs~~Partnership ofcould ~~such~~be ~~action.~~required to ~~Many~~suspend ~~states~~or ~~have~~cease ~~adopted~~operations ~~comparable~~in orcontaminated ~~more stringent statutes~~areas.

1211

Index

~~Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of the~~ The Partnership’s ~~operators’~~may ~~expected~~own ~~operations,~~producing ~~the~~properties ~~operators will generate wastes~~ that ~~may~~have ~~fall~~been ~~within~~used ~~CERCLA’s~~for ~~definition~~oil ~~of hazardous substance~~ and ~~may~~natural ~~dispose~~gas ofexploration ~~these~~and ~~wastes~~production atfor ~~disposal~~many ~~sites~~years. ~~owned~~Hazardous substances, ~~and~~wastes ~~operated~~or byhydrocarbons ~~others.~~may ~~Comparable~~have ~~state~~been ~~statutes~~released ~~may~~on ~~not~~or ~~provide~~under athe ~~comparable~~Partnership’s ~~exemption for petroleum~~properties, ~~and~~or ~~there~~on isor nounder ~~guarantee~~other ~~that~~locations, including ~~federal~~offsite ~~law~~locations, ~~will~~where ~~not~~such ~~adopt~~substances ~~more~~have ~~stringent~~been ~~requirements~~taken ~~with~~for ~~respect to the petroleum substances~~disposal. ~~The~~In ~~Partnership~~addition, ~~may~~some ~~also~~of be the ~~owner~~properties ofthe ~~sites~~Partnership has onacquired ~~which~~may ~~hazardous substances~~ have been ~~released.~~operated Ifby ~~contamination~~third isparties ~~discovered at a site on which the Partnership is~~ or ~~has~~by ~~been~~previous anowners ~~owner~~ or tooperators ~~which~~whose ~~the~~treatment ~~Partnership~~and ~~sent~~disposal of hazardous substances, wastes, ~~the~~or ~~Partnership~~hydrocarbons ~~could~~were benot ~~liable~~under ~~for~~Partnership ~~the~~control. ~~costs~~These ofproperties ~~investigation~~ and ~~remediation~~the ~~and~~substances ~~natural~~disposed ~~resources~~or ~~damages.~~released ~~Further,~~on ~~the~~them ~~Partnership~~may ~~could~~ be ~~required~~ subject to ~~suspend~~CERCLA, orRCRA ~~cease~~and ~~operations~~analogous instate ~~contaminated areas~~laws.

~~The~~In general, ~~Partnership~~the ~~may~~list ~~own~~of ~~producing~~substances ~~properties~~regulated ~~that~~as ~~have~~hazardous ~~been~~under ~~used~~CERCLA ~~for~~has ~~oil~~been ~~and~~expanding ~~natural~~over ~~gas exploration and production for many years~~time. ~~Hazardous~~For ~~substances~~example, ~~wastes~~in orMay ~~hydrocarbons~~2024, ~~may have been released on or under~~ the ~~Partnership’s~~EPA ~~properties,~~published a orfinal onrule ordesignating ~~under~~perfluorooctanoic ~~other~~acid ~~locations,~~(“PFOA”) ~~including~~and ~~offsite~~perfluorooctanesulfonic ~~locations,~~acid ~~where such substances have been taken for disposal. In addition~~(“PFOS”), ~~some~~both forms of ~~the~~prevalent ~~properties~~manufactured ~~the~~chemicals ~~Partnership~~known ~~has~~as ~~acquired~~per- ~~may have been operated by third parties or by previous owners or operators whose treatment~~ and ~~disposal~~polyfluoroalkyl ~~of hazardous~~ substances, ~~wastes~~(“PFAS”), oras ~~hydrocarbons~~CERCLA ~~were~~hazardous ~~not under Partnership control~~substances. The ~~These~~rulemaking ~~properties~~requires ~~and~~entities ~~the~~to ~~substances~~report ~~disposed~~to orregulators ~~released~~releases onof ~~them~~PFOA ~~may~~or bePFOS ~~subject~~above toreportable ~~CERCLA~~quantities, ~~RCRA~~ and ~~analogous~~imposes ~~state~~new ~~laws~~cleanup obligations for these chemicals.

In ~~general,~~ the ~~list of substances regulated as hazardous under CERCLA has been expanding over time. For example~~future, the ~~EPA~~Partnership ~~has~~could ~~taken~~be ~~steps~~required to ~~designate~~remediate asproperty, ~~hazardous~~including ~~certain highly prevalent manufactured chemicals known as per- and polyfluoroalkyl substances (“PFAS”)~~groundwater, ~~perfluorooctanoic~~containing ~~acid~~or ~~(“PFOA”)~~impacted ~~and~~by ~~perfluorooctanesulfonic~~previously ~~acid~~disposed wastes (~~“PFOS”).~~including Inwastes ~~April~~disposed ~~2023,~~or ~~the~~released ~~EPA~~by ~~requested~~prior ~~input~~owners ~~from~~or ~~the public in connection with the potential designation of seven additional PFAS as hazardous. If finalized~~operators, ~~the~~or ~~rulemaking~~property ~~would require entities to report to regulators releases of PFOA~~contamination, ~~PFOS~~including ~~and~~groundwater ~~certain~~contamination by ~~other~~prior ~~PFAS~~owners ~~above~~or ~~reportable~~operators) ~~quantities,~~or ~~and~~to ~~the~~perform ~~rulemaking~~remedial isplugging ~~likely~~operations to ~~culminate~~prevent infuture ~~new~~or ~~cleanup~~mitigate ~~obligations~~existing ~~for these chemicals~~contamination.

InClean Water 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.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. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for noncompliance 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.

~~The~~In ~~Federal Water Pollution Control Act~~2018, ~~also known as~~ the ~~Clean~~EPA ~~Water~~commenced ~~Act,~~a ~~and~~management ~~analogous~~study ~~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,~~extraction ~~into~~wastewater ~~state~~from ~~waters~~both conventional extraction and ~~waters~~unconventional ofextraction ~~the~~such ~~United~~as ~~States~~hydraulic fracturing. The purpose ~~discharge~~ of ~~pollutants~~this ~~into~~study ~~regulated waters~~ is ~~prohibited,~~to ~~except~~understand inif ~~accordance~~support ~~with~~exists ~~the~~for ~~terms~~new ofregulations athat ~~permit~~would ~~issued~~allow byfor ~~the~~a ~~EPA~~broader ~~or an analogous state agency. The Clean Water Act also prohibits the~~ discharge of ~~dredge~~oil and ~~fill~~natural gas ~~material~~extraction inwastewater ~~regulated~~directly ~~waters,~~to ~~including~~surface ~~wetlands,~~waters ~~unless~~under ~~authorized by a permit issued by~~ the U.S. Army Corps of Engineers. 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’s ~~and~~National ~~analogous~~Pollutant ~~state~~Discharge ~~laws~~Elimination ~~and~~System, in ~~regulations.~~addition Into the ~~event~~primary ofexisting andisposal ~~unauthorized~~methods ~~discharge~~ of ~~wastes,~~underground ~~the~~injection ~~Partnership~~or ~~may~~discharge beto ~~liable~~centralized ~~for~~wastewater ~~penalties~~treatment ~~and cleanup and response costs~~facilities. The ~~federal~~EPA ~~Clean~~produced ~~Water~~a ~~Act~~report ~~only~~of ~~regulates~~its ~~surface~~findings ~~waters.~~in ~~However~~May 2020, ~~most~~which ofdid ~~the~~not ~~state~~announce ~~analogs~~any tonew ~~the~~regulatory ~~Clean~~requirements ~~Water~~regarding ~~Act~~oil ~~also~~and ~~regulate~~natural gas ~~discharges~~extraction ~~which impact groundwater~~wastewater.

In April ~~2018~~2020, the EPA ~~commenced~~and the U.S. Army Corps issued a ~~management~~navigable ~~study~~waters protection rule under the Clean Water Act, narrowing the definition of ~~oil~~“waters ~~and~~of ~~gas~~the ~~extraction~~United ~~wastewater~~States” ~~from~~for ~~both~~which ~~conventional~~discharge ~~extraction~~permits ~~and~~would ~~unconventional~~be ~~extraction~~required ~~such~~during asdevelopment. ~~hydraulic~~In ~~fracturing~~August 2021, the U.S. District ~~The~~Court ~~purpose~~for the District of Arizona vacated and remanded the new rule. Based on this ~~study~~ruling, isin toDecember ~~understand~~2022, ifthe ~~support~~EPA ~~exists~~and ~~for~~the U.S. ~~new~~Army ~~regulations~~Corps finalized a rule that ~~would~~in ~~allow~~practice ~~for~~restored athe ~~broader~~old ~~discharge~~definition. ofThis ~~oil~~December 2022 rule was challenged by states and ~~gas~~industry groups, ~~extraction~~and ~~wastewater~~in ~~directly~~May to2023, ~~surface~~in ~~waters~~a ~~under~~case called Sackett v. U.S. Environmental Protection Agency, the United States Supreme Court adopted a narrow test for wetlands covered by the Clean Water Act’s. ~~National~~In ~~Pollutant~~response ~~Discharge~~to ~~Elimination~~this ~~System~~decision, inthe ~~addition~~EPA toand the ~~primary~~U.S. ~~existing~~Army ~~disposal~~Corps ~~methods~~issued a revised definition of ~~underground~~“waters ~~injection~~of orthe ~~discharge~~United States” that was meant to ~~centralized~~be ~~wastewater~~consistent ~~treatment~~with ~~facilities~~the Supreme Court’s ruling. ~~The~~This ~~EPA~~revised definition, ~~produced~~however, has been subject to legal challenges by states, industry groups and individual landowners. In June 2024, a ~~report~~federal district ofcourt ~~its~~upheld ~~findings~~the inU.S. ~~May~~Army ~~2020~~Corps’ revised decision, ~~which~~but ~~did~~other ~~not~~legal ~~announce~~challenges remain ongoing. To the extent that any future ~~new~~rules ~~regulatory~~expand ~~requirements~~the ~~regarding~~scope ~~oil~~of the Clean Water Act’s jurisdiction, we could face increased costs and ~~gas~~delays ~~extraction~~with ~~wastewater~~respect to obtaining permits for activities in jurisdictional waters of the United States, including wetlands.

InSafe Drinking ~~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~~Hydraulic the new rule. Based on this ruling, in December 2022, the EPA and the U.S. Army Corps finalized a rule that in practice restored the old definition. This December 2022 rule was challenged by states and industry groups, and in May 2023, in a case called Sackett v. U.S. Environmental Protection Agency, the United States Supreme Court adopted a narrow test for wetlands covered by the Clean Water Act. In response to this decision, the EPA and the U.S. Army Corps issued a revised definition of “waters of the United States” that was meant to be consistent with the Supreme Court’s ruling. This revised definition, however, is being challenged by states and industry groups. The litigation is ongoing. 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.Fracturing

13Many 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 natural 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).

~~Index~~12

~~Safe Drinking Water Act and Hydraulic Fracturing~~Index

~~Many~~In prior ofsessions, Congress has considered legislation to amend the ~~properties~~federal Safe Drinking Water Act to remove the ~~Partnership~~exemption ~~owns~~for ~~will~~hydraulic fracturing operations and require ~~additional~~reporting ~~drilling~~and ~~operations~~disclosure toof ~~fully~~chemicals ~~develop~~used by the ~~reserves~~oil ~~attributable~~and tonatural gas industry in the ~~properties~~hydraulic fracturing process. ~~Hydraulic~~This ~~fracturing~~legislation ~~involves~~has ~~the~~not ~~injection~~passed. A number of ~~water~~states, ~~sand~~local and ~~chemicals~~regional ~~under~~regulatory ~~pressure~~authorities ~~into~~have ~~formations~~or toare ~~fracture~~considering ~~the~~hydraulic fracturing ~~surrounding~~regulation ~~rock~~ and ~~stimulate~~other ~~production.~~regulations ~~Hydraulic~~imposing ~~fracturing~~new ~~activities~~or ~~are~~more ~~typically~~stringent ~~regulated~~permitting, bydisclosure ~~state~~and ~~oil~~well ~~and~~construction ~~gas~~requirements on ~~commissions~~hydraulic ~~but~~fracturing ~~not~~operations ator ~~the~~restricting ~~federal~~or ~~level,~~banning ashydraulic fracturing. Further, the ~~federal~~EPA ~~Safe~~has ~~Drinking~~issued ~~Water~~an ~~Act~~effluent ~~expressly~~limitations guideline ~~excludes~~prohibiting ~~regulation~~the discharge of ~~these~~wastewater ~~fracturing~~from ~~activities~~onshore ~~(except~~unconventional ~~for~~oil ~~fracturing~~and ~~activities~~natural ~~involving~~gas ~~the~~extraction ~~use~~facilities ofto ~~diesel)~~publicly owned treatment plants.

In December ~~prior sessions~~2016, ~~Congress~~the ~~has~~EPA ~~considered~~released ~~legislation~~its tofinal ~~amend~~report on the ~~federal~~potential ~~Safe~~impacts ~~Drinking~~of ~~Water~~hydraulic ~~Act~~fracturing toon ~~remove~~drinking ~~the~~water ~~exemption~~resources, ~~for~~concluding that ~~hydraulic~~“water ~~fracturing~~cycle” ~~operations~~activities ~~and~~associated ~~require~~with ~~reporting~~hydraulic ~~and~~fracturing ~~disclosure~~may ofimpact ~~chemicals~~drinking ~~used~~water byresources ~~the~~“under ~~oil~~some circumstances,” ~~and~~including ~~natural~~water ~~gas~~withdrawals ~~industry~~for fracturing in ~~the~~times ~~hydraulic~~or ~~fracturing~~areas ~~process.~~of ~~This~~low ~~legislation~~water ~~has~~availability; ~~not~~surface ~~passed.~~spills Aduring ~~number~~the management of ~~states~~fracturing fluids, ~~local~~chemicals ~~and~~or ~~regional~~produced ~~regulatory~~water; ~~authorities~~injection ~~have~~of orfracturing ~~are~~fluids ~~considering~~into ~~hydraulic~~wells ~~fracturing~~with ~~regulation~~inadequate ~~and~~mechanical ~~other~~integrity; injection ~~regulations~~of ~~imposing~~fracturing ~~new~~fluids ordirectly ~~more~~into ~~stringent~~groundwater ~~permitting,~~resources; ~~disclosure~~discharge ~~and~~of ~~well~~inadequately ~~construction~~treated ~~requirements~~fracturing onwastewater ~~hydraulic~~to ~~fracturing~~surface waters; ~~operations~~and ordisposal ~~restricting~~ or ~~banning~~storage ~~hydraulic~~of fracturing. ~~Further,~~wastewater ~~the~~in ~~EPA~~unlined ~~has~~pits. ~~issued~~This anreport ~~effluent~~could ~~limitations~~result ~~guideline~~in ~~prohibiting~~additional ~~the~~regulatory ~~discharge~~scrutiny that ofcould ~~wastewater~~make ~~from~~it ~~onshore~~more ~~unconventional~~difficult ~~oil~~to ~~and~~perform ~~natural~~hydraulic ~~gas~~fracturing ~~extraction~~and ~~facilities~~increase tothe ~~publicly~~Partnership’s ~~owned~~costs ~~treatment~~of ~~plants~~compliance and business.

InIf ~~December~~new ~~2016,~~laws ~~the~~or ~~EPA~~regulations ~~released~~imposing ~~its~~significant ~~final~~restrictions or ~~report~~conditions on ~~the potential impacts of~~ hydraulic fracturing onactivities ~~drinking~~are ~~water~~adopted ~~resources,~~in ~~concluding~~areas ~~that~~where ~~“water~~the ~~cycle”~~Partnership ~~activities~~owns ~~associated~~properties ~~with~~that ~~hydraulic~~require ~~fracturing~~additional ~~may~~drilling, the ~~impact~~Partnership ~~drinking~~could ~~water~~incur ~~resources~~substantial ~~“under~~compliance ~~some~~costs ~~circumstances,”~~and ~~including~~such ~~water~~requirements ~~withdrawals~~could ~~for~~adversely ~~fracturing~~delay ~~in times~~ or ~~areas~~restrict ofits ~~low~~ability ~~water~~to ~~availability;~~conduct fracturing ~~surface~~activities ~~spills~~on ~~during~~its ~~the~~assets. ~~management~~In ofDecember ~~fracturing fluids~~2017, ~~chemicals~~the orBureau ~~produced water; injection~~ of ~~fracturing~~Land ~~fluids~~Management ~~into~~(“BLM”) ~~wells~~rescinded ~~with~~its ~~inadequate~~own ~~mechanical~~rule ~~integrity;~~from 2015 ~~injection~~that ofwould ~~fracturing~~have ~~fluids~~required ~~directly~~oil ~~into~~and ~~groundwater~~natural ~~resources;~~gas ~~discharge~~companies ~~of inadequately treated fracturing wastewater~~ to ~~surface~~seek ~~waters;~~approval ~~and~~from ~~disposal~~BLM orbefore ~~storage~~conducting ofhydraulic fracturing ~~wastewater~~operations on inpublic ~~unlined~~lands ~~pits.~~and ~~This~~for ~~report~~companies ~~could result in additional regulatory scrutiny that could make it more difficult~~ to ~~perform~~disclose ~~hydraulic fracturing and increase~~ the ~~Partnership’s~~chemicals ~~costs~~used ofin ~~compliance~~fracking ~~and business~~fluid.

IfOil Pollution 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.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.

The operations of the Partnership’s operators are subject to the federal Clean Air ~~Emissions~~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.

~~The~~On April ~~operations~~17, of2012, the ~~Partnership’s~~EPA ~~operators~~issued ~~are~~final ~~subject~~rules tothat ~~the~~subject ~~federal~~oil ~~Clean~~and ~~Air~~natural ~~Act~~gas production, ~~or CAA~~processing, transmission and ~~analogous~~storage ~~state~~operations to ~~laws~~regulation. ~~and~~The ~~local~~EPA ~~ordinances~~rules ~~governing~~include ~~the~~standards ~~control~~for completions of ~~emissions~~hydraulically ~~from~~fractured ~~sources~~natural ofgas ~~air pollution~~wells. ~~The~~Before ~~CAA~~January ~~and~~1, ~~analogous~~2015, these ~~state~~standards ~~laws~~required ~~require~~owners/operators ~~new~~to ~~and~~reduce ~~modified~~volatile ~~sources~~organic ofcompound, ~~air~~or ~~pollutants~~VOC, toemissions ~~obtain~~from ~~permits~~natural ~~prior~~gas not sent to ~~commencing~~the ~~construction.~~gathering line ~~Major~~during ~~sources~~well ofcompletion ~~air~~either ~~pollutants~~by ~~are~~flaring, ~~subject~~using toa ~~more~~completion ~~stringent~~combustion device, ~~federally~~or ~~imposed~~by ~~requirements~~capturing ~~including~~the ~~additional~~natural ~~permits.~~gas ~~Federal~~using ~~and~~green ~~state~~completions with ~~laws~~a ~~designed~~completion tocombustion ~~control~~device. ~~hazardous~~Beginning orJanuary ~~toxic~~1, ~~air pollutants~~2015, ~~might~~operators ~~require~~must ~~installation~~capture ofthe ~~additional~~natural ~~controls.~~gas ~~Administrative~~and ~~enforcement~~make ~~actions~~it available for ~~failure~~use or tosale, ~~comply~~which ~~strictly~~can ~~with~~be ~~air~~done ~~pollution~~through ~~regulations~~the oruse ~~permits~~of ~~are~~“green ~~generally~~completions.” ~~resolved~~The bystandards ~~payment~~are ofapplicable ~~monetary~~to ~~fines~~newly fractured wells and ~~correction~~also ofexisting ~~any~~wells ~~identified~~that ~~deficiencies~~are refractured. ~~Alternatively~~Further, ~~regulatory~~the ~~agencies~~finalized ~~could~~regulations ~~bring~~established ~~lawsuits~~specific ~~for~~new ~~civil~~requirements ~~penalties~~for oremissions from ~~seek~~compressors, ~~injunctive~~controllers, ~~relief~~dehydrators, ~~requiring~~storage ~~the Partnership to forego construction~~tanks, ~~modification~~natural orgas ~~operation~~processing ofplants and certain ~~air~~other ~~emission sources~~equipment.

14In 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.

~~Index~~13

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.Index

In ~~August~~December ~~2020~~2023, the EPA ~~removed~~announced ~~sources~~a infinal ~~the~~rule ~~transmission~~to reduce methane and ~~storage~~VOC ~~segment~~emissions from ~~regulation under~~ the ~~2012~~oil and ~~2016~~natural ~~New~~gas ~~Source~~sector. ~~Performance~~The ~~Standards~~rule (“consists of NSPS”) for ~~the~~methane ~~oil~~ and ~~natural~~VOCs ~~gas~~emissions ~~industry~~from ~~for~~new sources ~~ozone-forming~~and ~~VOCs~~emissions ~~and~~guidelines for ~~greenhouse~~states ~~gases~~to ~~(“GHGs”)~~follow ~~from~~in ~~methane~~developing implementation plans that will cover existing sources. OnAny ~~June~~“new” sources ~~30,~~(those ~~2021~~constructed, ~~President~~modified ~~Biden~~or ~~signed~~reconstructed ~~into~~after ~~law~~December a6, ~~joint~~2022) ~~resolution~~will ofneed ~~Congress~~to ~~disapproving~~comply ~~this~~with ~~final~~the ~~rule~~2023 NSPS. ~~The~~Any ~~resolution~~“existing” sources ~~had~~(those ~~the~~constructed ~~effect~~before ofDecember ~~reinstating~~6, ~~the~~2022) ~~2012~~will ~~and~~be ~~2016~~subject ~~VOC~~to ~~and~~the ~~methane~~ standards ~~for~~promulgated pursuant to the ~~transmission~~state ~~and~~implementation plans. ~~storage~~States ~~segment,~~have astwo ~~well~~years asfrom the ~~methane~~rule’s ~~standards~~effective ~~for~~date to submit implementation plans to the ~~production~~EPA, and ~~processing~~companies ~~segments~~have three years from this submission date to comply.

In The December 2023 rule, for the ~~EPA~~first ~~announced~~time, aextends ~~final~~the ~~rule~~categories toof ~~reduce~~sources covered by methane and VOC ~~emissions~~emission ~~from~~standards ~~the~~to ~~oil~~flared ~~and~~ gas, compressors ~~sector.~~at ~~The~~centralized ~~rule~~tank ~~consists~~batteries, ofliquids ~~NSPS~~unloading, ~~for~~and ~~methane~~process ~~and~~pumps. ~~VOCs~~Most ~~emissions~~routine flaring from ~~new~~natural ~~sources~~gas ~~and~~wells ~~emissions~~will ~~guidelines~~be phased ~~for~~out ~~states~~through routing to ~~follow~~a incontrol ~~developing~~device, ~~implementation~~or ~~plans~~routing ~~that~~the ~~will~~flared ~~cover~~gas ~~existing~~to ~~sources.~~a ~~Any~~sales ~~“new”~~line, ~~sources~~using ~~(those~~it ~~constructed,~~for ~~modified~~fuel or ~~reconstructed~~another ~~after~~beneficial ~~December 6~~purpose, or ~~2022)~~reinjecting ~~will~~it ~~need~~into toa ~~comply~~well. ~~with~~The ~~the~~rule ~~2023~~requires ~~NSPS.~~that ~~Any~~all wellhead sites and compressor stations are regularly monitored for leaks, also known as “~~existing~~fugitive emissions.” ~~sources~~Wellhead-only ~~(those~~sites ~~constructed~~are ~~before~~no ~~December~~longer 6,excluded. ~~2022)~~The ~~will~~type beand ~~subject~~frequency toof monitoring are based on the ~~standards~~amount ~~promulgated~~and ~~pursuant~~types toof ~~the~~equipment ~~state~~at ~~implementation~~a ~~plans.~~site, ~~States~~rather ~~have~~than ~~two~~on ~~years~~estimated emissions from ~~the~~a ~~rule’s~~site. ~~effective~~Control ~~date~~devices are subject to ~~submit~~continuous monitoring ~~implementation~~and ~~plans~~regular toinspections. The rule authorizes the ~~EPA,~~use of new advanced measurement technologies such as on-site sensor networks and ~~companies~~aerial ~~have~~flyovers ~~three~~using ~~years~~remote-sensing ~~from~~technologies, ~~this~~although ~~submission~~any ~~date~~new totechnologies ~~comply~~must be preapproved by the EPA.

~~The~~A novel feature of the December 2023 rule, ~~for~~is the ~~first~~establishment ~~time,~~of ~~extends~~ the ~~categories~~“Super ofEmitter ~~sources~~Program.” ~~covered~~Under bythe ~~methane and VOC emission standards to flared gas~~program, ~~compressors~~the atEPA ~~centralized~~will certify ~~tank~~third ~~batteries,~~parties ~~liquids~~to ~~unloading,~~monitor ~~and~~for ~~process~~“super ~~pumps~~emitter events.” ~~Most~~The ~~routine~~certified ~~flaring~~third ~~from~~parties ~~natural~~are ~~gas~~authorized ~~wells~~to ~~will~~report beany ~~phased~~such events ~~out through routing~~ to athe ~~control device~~EPA, orand ~~routing~~ the ~~flared~~EPA, ~~gas~~upon toverification aof ~~sales~~the ~~line~~event, ~~using~~will itrequire ~~for~~the ~~fuel~~owner or ~~another~~operator ~~beneficial~~to ~~purpose,~~correct orthe ~~reinjecting~~cause itof ~~into~~the ~~a well~~event. The ~~rule~~certified ~~requires~~third ~~that~~parties ~~all wellhead sites and compressor stations~~ are ~~regularly~~not ~~monitored~~allowed ~~for~~to ~~leaks,~~enter ~~also~~an ~~known~~owner asor ~~“fugitive~~operator’s ~~emissions.”~~well ~~Wellhead-only~~site ~~sites~~or ~~are~~other ~~no longer excluded. The type and frequency of monitoring are based on the amount and types of equipment at a site~~facility, ~~rather~~but ~~than~~instead onmust ~~estimated emissions from a site. Control devices are subject to continuous monitoring and regular inspections. The rule authorizes the~~ use ~~of new advanced measurement technologies such as on~~EPA-~~site sensor networks and aerial flyovers using~~ approved remote-sensing technologies, ~~although~~such ~~any~~as ~~new~~those ~~technologies~~used ~~must~~on besatellites ~~preapproved~~or byin ~~the~~aerial ~~EPA~~surveys.

AIn November ~~novel~~2018, ~~feature~~the ofEPA ~~the~~revised ~~December~~a ~~2023~~previously stayed rule isdefining ~~the~~site ~~establishment~~aggregation offor ~~the~~air ~~“Super~~permitting ~~Emitter Program~~purposes.” Under ~~the~~this ~~program~~rule, ~~the~~it ~~EPA~~is possible ~~will~~that ~~certify~~some ~~third~~sites ~~parties~~could torequire ~~monitor~~additional ~~for~~permitting ~~“super~~under ~~emitter events.” The certified third parties are authorized to report any such events to~~ the ~~EPA,~~Clean ~~and~~Air ~~the EPA~~Act, ~~upon~~an ~~verification~~outcome ofthat ~~the~~could ~~event,~~result ~~will~~in ~~require~~costs ~~the~~and ~~owner or operator~~ delays to ~~correct~~ the ~~cause of the event. The certified third parties are not allowed to enter an owner or operator~~Partnership’s ~~well site or other facility, but instead must use EPA-approved remote-sensing technologies, such as those used on satellites or in aerial surveys~~operations.

In On November ~~2018~~18, 2016, the ~~EPA~~BLM ~~revised~~published a ~~previously~~final ~~stayed~~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 ~~defining~~was ~~site~~challenged ~~aggregation~~and ~~for~~struck ~~air~~down ~~permitting~~in ~~purposes~~federal court in 2020. ~~Under~~In ~~this~~April ~~rule~~2024, itthe isBLM ~~possible~~issued a new final rule that ~~some~~limits ~~sites~~monthly ~~could~~royalty-free ~~require~~natural ~~additional~~gas ~~permitting~~flaring ~~under~~at wells on federal and tribal lands and strengthens requirements to mitigate waste from these wells, including through the ~~Clean~~implementation ~~Air~~of ~~Act~~a leak detection and repair program. Several states brought legal challenges to the new final rule. In September 2024, ana ~~outcome~~federal ~~that~~court ~~could~~issued ~~result~~a preliminary injunction blocking enforcement of the rule in ~~costs~~the plaintiff states of North Dakota, Texas, Montana, Wyoming, and ~~delays~~Utah, toand the ~~Partnership’s~~litigation remains ~~operations~~ongoing. BLM is enforcing the new final rule in states that are not covered by the court order.

On In November 182021, ~~2016,~~ the ~~BLM~~Department ~~published~~of aTransportation ~~final~~finalized ~~rule~~rules that ~~was intended to reduce waste of natural gas from venting~~brought, ~~flaring,~~for ~~and~~the ~~leaks~~first ~~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~~time, ~~the~~significant ~~BLM~~miles ~~proposed~~of ~~a new rule that limits monthly royalty-free~~ natural gas ~~flaring~~gathering pipelines atunder ~~wells on~~ federal ~~and~~safety ~~tribal~~regulation ~~lands~~ and ~~strengthens~~imposed new requirements to ~~mitigate~~report ~~waste from these wells~~incidents, including ~~through~~methane ~~the~~leaks, ~~implementation~~from ofthese ~~a leak detection and repair program~~pipelines.

InNational Environmental ~~November~~Policy 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.Act

15Oil 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.

~~Index~~The first 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 Phase 1 of a planned two-part NEPA rulemaking effort. The Phase 1 rule reversed most of the rollbacks introduced through the previous Trump-era regulations. It provides agencies with more flexibility to define the purpose and need of a proposed action, and to work with project proponents and communities to mitigate environmental harm by analyzing alternative designs and approaches; establishes NEPA procedures as a floor rather than a ceiling; restoring the ability of federal agencies to tailor their NEPA procedures to meet agency-specific needs; and restores and clarifies the definitions of direct, indirect, and cumulative effects to include environmental impacts related to climate change and environmental justice. In May 2024, the Biden administration finalized the Phase 2 rule. This rule accelerates the deployment of clean energy projects by potentially exempting them from the requirement of issuing environmental impact statements; require agencies to consider climate change effects and mitigative alternatives, including, where feasible, quantifying GHG emissions; require agencies to consider environmental justice issues such as reducing disproportionate effects on communities; and remove onerous content-requirements on public comments to proposed projects.

~~National Environmental Policy Act~~14

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.Index

~~The~~Climate Change 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 Phase 1 of a planned two-part NEPA rulemaking effort. The Phase 1 rule reversed most of the rollbacks introduced through the Trump-era regulations. It provides agencies with more flexibility to define the purpose and need of a proposed action, and to work with project proponents and communities to mitigate environmental harm by analyzing alternative designs and approaches; establishes NEPA procedures as a floor rather than a ceiling; restoring the ability of federal agencies to tailor their NEPA procedures to meet agency-specific needs; and restores and clarifies the definitions of direct, indirect, and cumulative effects to include environmental impacts related to climate change and environmental justice. In July 2023, the Biden administration proposed the Phase 2 rule. This rule would accelerate the deployment of clean energy projects by potentially exempting them from the requirement of issuing environmental impact statements; require agencies to consider climate change effects and mitigative alternatives; require agencies to consider environmental justice issues such as reducing disproportionate effects on communities; and remove onerous content-requirements on public comments to proposed projects.Legislation

~~Climate~~More stringent ~~Change~~laws ~~Legislation~~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.

~~More~~The EPA ~~stringent~~has ~~laws~~adopted ~~and~~a ~~regulations~~mandatory ~~relating to climate change and~~ GHG emissions ~~may~~reporting beprogram ~~adopted~~that inimposes ~~the~~reporting ~~future~~ and ~~could~~monitoring ~~cause~~requirements ~~the~~on ~~Partnership~~various totypes ~~incur~~of ~~material~~facilities and ~~expenses~~industries inincluding ~~complying~~onshore ~~with~~and ~~them.~~offshore ~~Both~~oil ~~houses~~and ofnatural ~~Congress~~gas ~~have~~production, ~~considered~~processing, ~~legislation~~transmission, tostorage, ~~reduce~~and ~~emissions~~distribution offacilities. In ~~GHGs~~May 2024, ~~but~~the noEPA ~~legislation~~issued ~~has~~a ~~yet~~final ~~passed.~~rule Into ~~the~~strengthen, ~~absence~~expand ofand ~~comprehensive~~update ~~federal~~methane ~~legislation~~emissions onreporting ~~GHG~~requirements ~~emission~~for ~~control,~~petroleum ~~the~~and natural ~~EPA~~gas ~~attempted~~systems tounder ~~require~~ the ~~permitting of~~ GHG emissions; ~~although~~reporting ~~the~~program. ~~Supreme~~The ~~Court~~final ~~struck~~rule ~~down~~includes ~~the~~changes ~~permitting~~to ~~requirements,~~reporting itobligations ~~upheld~~that ~~the~~may ~~EPA’s~~involve expanded ~~authority to control GHG~~ emissions ~~when~~monitoring aand ~~permit~~reporting isrequirements ~~required~~and ~~due~~changes to emissions ofcalculation ~~other pollutants~~methodologies.

The Biden ~~EPA~~administration ~~has~~declared ~~adopted~~efforts ato ~~mandatory~~manage ~~GHG~~and ~~emissions~~control ~~reporting~~climate ~~program~~change ~~that~~a ~~imposes~~priority, ~~reporting~~evidenced ~~and~~by ~~monitoring~~the ~~requirements~~immediate onre-commitment ~~various~~of ~~types~~the United ofStates ~~facilities~~to ~~and~~the ~~industries~~Paris ~~including~~Agreement. ~~onshore~~The ~~and~~second ~~offshore~~Trump ~~oil~~administration ~~and~~withdrew ~~natural~~the ~~gas~~United ~~production,~~States ~~processing,~~from ~~transmission,~~the ~~storage~~Paris Agreement, ~~and~~as ~~distribution~~was ~~facilities~~done during the first Trump administration.

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 GHG emissions. In January 2021, the first Trump administration EPA issued a rule requiring the EPA to find that an individual industry, such as the power sector or oil and natural gas operators, collectively emits at least 3% of total U.S. GHG 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 the 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, the Biden-era EPA ~~has~~was committed to using the full scope of its authority to combat climate change. Among other things, in September 2022 the 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.

16In addition to possible federal regulation, a number of states, individually and regionally as well as some localities, are considering or have implemented GHG regulatory programs or other steps to reduce GHG emissions. These 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.

~~Index~~Endangered Species Act

InThe Endangered ~~addition~~Species Act (“ESA”) was established to ~~possible~~protect ~~federal~~endangered ~~regulation~~and threatened species. Pursuant to that act, if a ~~number~~species is oflisted ~~states~~as threatened or endangered, ~~individually~~restrictions ~~and~~may ~~regionally~~be asimposed ~~well~~on asactivities ~~some~~that ~~localities,~~would ~~are~~harm ~~considering~~the species or ~~have~~that ~~implemented~~would ~~GHG~~adversely affect ~~regulatory~~that ~~programs~~species’ orhabitat. ~~other~~Similar ~~steps~~protections are offered to ~~reduce~~migratory ~~GHG~~birds ~~emissions.~~under ~~These~~the ~~regional,~~Migratory ~~state~~Bird ~~and~~Treaty ~~local~~Act. ~~initiatives~~The Partnership’s operators may ~~result~~conduct inoperations ~~so-called~~on ~~cap~~oil and ~~trade~~natural ~~programs,~~gas ~~under~~leases ~~which~~that ~~overall~~have ~~GHG~~species ~~emissions~~that are ~~limited~~listed and ~~GHG~~species ~~emissions~~that ~~are~~could ~~then~~be ~~allocated~~listed ~~and~~as threatened ~~sold,~~or ~~and~~endangered ~~possibly~~under ~~other~~the ~~regulatory~~act. ~~requirements,~~The ~~that~~U.S. ~~could~~Fish ~~result~~and inWildlife Service designates the ~~Partnership~~species’ ~~incurring~~protected ~~material~~habitat ~~expenses~~as part of the effort to ~~comply,~~protect ethe species.~~g.,~~ byA ~~being~~protected ~~required~~habitat todesignation ~~purchase~~or the mere presence of threatened or endangered species could result in material restrictions to ~~surrender~~use ~~allowances~~of ~~for~~the ~~GHGs~~land ~~resulting~~and ~~from~~may ~~its~~materially ~~operations.~~delay ~~The~~or ~~federal,~~prohibit ~~regional~~land access for oil and ~~local~~natural ~~regulatory~~gas ~~initiatives~~development. It also ~~could~~may adversely ~~affect~~impact the ~~marketability~~value of the ~~oil~~affected ~~and~~properties ~~natural~~that ~~gas~~ the Partnership ~~produces~~owns. The ~~impact~~designation of ~~such~~previously ~~future~~unprotected ~~programs~~species as ~~cannot~~threatened beor ~~predicted,~~endangered ~~but~~in areas where the Partnership ~~does~~might ~~not~~conduct ~~expect~~operations ~~its~~could ~~operations~~result toin belimitations ~~affected~~or ~~any~~prohibitions ~~differently~~on ~~than~~its activities ~~other~~and ~~similarly~~could ~~situated~~adversely ~~domestic~~impact ~~competitors~~the value of its leases.

~~Endangered Species Act~~15

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.Index

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 further 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~~March ~~2021~~2024, the ~~Fish and Wildlife Service under the~~ Biden administration issued ~~stated~~three ~~its~~rules ~~plan~~that torevised ~~rescind or revise most of~~ the ~~2019~~rules ~~revisions.~~issued Inunder ~~June 2023,~~ the ~~Biden~~first Trump administration. ~~proposed~~The ~~revoking~~revisions ~~certain~~include ~~Trump-era rules, including~~ reinstating the rule that automatically extends protections for “endangered” species to “threatened” species, and the rule requiring that listing, delisting or reclassification of species be made “without reference to possible economic or other impacts of such determination.” among ~~Pursuant~~other ~~to a number of federal court rulings in 2022, however, any unamended 2019 Trump-era rules under the ESA will 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.

17Drilling and Production

~~Index~~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:

~~Drilling~~● the location of wells; ● the method of drilling, completing and ~~Production~~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.

~~Statutes, rules~~ State and federal regulations ~~affecting~~are ~~exploration~~generally ~~and~~intended ~~production~~to ~~undergo~~prevent ~~constant~~waste ~~review~~of oil and ~~often~~natural ~~are amended~~gas, ~~expanded~~protect ~~and~~correlative ~~reinterpreted,~~rights ~~making~~to ~~difficult~~produce ~~the~~oil ~~prediction~~and natural ofgas ~~future~~between ~~costs~~owners orin ~~the~~a ~~impact~~common ofreservoir ~~regulatory~~or ~~compliance~~formation, ~~attributable~~control tothe ~~new~~amount ~~laws~~of oil and ~~statutes.~~natural ~~The~~gas ~~regulatory~~produced ~~burden~~by onassigning ~~the~~allowable rates ~~oil~~of production and ~~natural~~control ~~gas~~contamination ~~industry~~of ~~increases~~ the ~~cost~~environment. ofPipelines ~~doing business~~ and, ~~consequently,~~natural ~~affects~~gas ~~its~~plants ~~profitability.~~operated ~~The~~by ~~drilling~~other ~~and~~companies ~~production~~that ~~operations~~provide midstream ~~performed~~services byto the Partnership’s ~~contracted operators~~ are also subject to ~~various~~the ~~types~~jurisdiction of ~~regulation~~various ~~at the~~ federal, state and local ~~levels.~~authorities, ~~These~~which ~~types~~can affect ofthe ~~regulation~~Partnership’s ~~include~~operations. ~~requiring~~State ~~permits~~laws ~~for~~also regulate the ~~drilling~~size ~~of wells, drilling bonds~~ and ~~reports~~shape ~~concerning~~of ~~operations.~~drilling ~~Most states~~ and ~~some~~spacing ~~counties~~units ~~and~~or ~~municipalities~~proration inunits governing ~~which~~ the ~~Partnership~~pooling ~~operates~~of ~~also~~oil ~~regulate~~and ~~one~~natural orgas ~~more of the following:~~properties.

●States generally ~~the~~impose ~~location~~a ofproduction, ~~wells;~~ad ●valorem ~~the~~or ~~method~~severance oftax ~~drilling,~~with ~~completing~~respect ~~and~~to ~~operating wells; ●~~ the ~~surface~~production ~~use~~ and ~~restoration~~sale of ~~properties~~oil ~~upon~~and ~~which~~natural ~~wells~~gas ~~are~~within ~~drilled;~~their respective ●jurisdictions. ~~the~~States ~~plugging~~do ~~and~~not ~~abandoning~~generally ofregulate ~~wells;~~wellhead ●prices ~~the~~or ~~marketing,~~engage ~~transportation~~in ~~and~~other, ~~reporting~~similar ofdirect ~~production;~~economic ●regulation, ~~notice~~but there tocan ~~surface~~be ~~owners~~no ~~and~~assurance ~~other~~they ~~third~~will ~~parties;~~not ~~and~~do ●so ~~produced~~in ~~water~~the ~~and waste disposal~~future.

~~State~~In addition, ~~and~~a ~~federal~~number ~~regulations~~of ~~are~~states, ~~generally~~such ~~intended~~as toNorth ~~prevent~~Dakota ~~waste~~where ofthe ~~oil~~Partnership’s ~~and~~properties ~~natural~~are ~~gas~~located, ~~protect correlative rights to produce oil~~ and ~~natural~~some ~~gas~~tribal ~~between~~nations ~~owners~~have enacted insurface adamage ~~common~~statutes, ~~reservoir~~ or ~~formation,~~SDAs. ~~control~~These ~~the~~laws ~~amount~~are ofdesigned ~~oil~~to ~~and~~compensate ~~natural~~for ~~gas~~damage ~~produced~~caused by ~~assigning~~oil ~~allowable rates of production~~ and ~~control contamination of the environment. Pipelines and~~ natural gas ~~plants~~development operations. ~~operated~~Most bySDAs ~~other~~contain ~~companies~~entry ~~that~~notification ~~provide~~and ~~midstream~~negotiation ~~services~~requirements to ~~the~~facilitate ~~Partnership~~contact ~~are~~between ~~also~~operators ~~subject~~and tosurface ~~the~~owners/users. Most ~~jurisdiction~~also ofcontain ~~various~~bonding ~~federal,~~requirements ~~state~~ and ~~local~~require ~~authorities,~~specific ~~which~~payments ~~can~~by ~~affect~~ the ~~Partnership’s~~operator ~~operations.~~to ~~State~~surface ~~laws~~owners/users ~~also~~in ~~regulate~~connection ~~the~~with ~~size~~ exploration and ~~shape~~producing ofactivities. ~~drilling~~Costs and ~~spacing~~delays ~~units~~associated orwith ~~proration~~SDAs ~~units~~could ~~governing~~impair ~~the~~operational ~~pooling~~effectiveness ~~of oil~~ and ~~natural~~increase ~~gas~~development ~~properties~~costs.

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.16

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.Index

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.

18Federal Regulation of Oil, Natural Gas and Natural Gas Liquids, including Regulation of Transportation

~~Index~~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.

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

~~The~~Under FERC’s ~~availability,~~current ~~terms~~regulatory ~~and~~regime, ~~cost~~interstate ofnatural gas transportation ~~service~~services ~~significantly~~must ~~affect~~be ~~sales~~provided ofon ~~natural~~an ~~gas.~~open-access, ~~The~~non-discriminatory basis ~~interstate~~at ~~transportation~~cost-based ~~and~~rates ~~sale~~or ~~for~~at ~~resale~~market-based ofrates ~~natural~~if ~~gas~~the ~~are~~transportation ~~subject~~market toat ~~federal~~issue ~~regulation,~~is ~~including~~sufficiently ~~regulation~~competitive. ofAmong ~~the~~other ~~terms~~things, the ~~conditions~~FERC-regulated ~~and~~tariffs, ~~rates~~under ~~for~~which interstate ~~transportation,~~pipelines ~~storage~~provide ~~and~~such ~~various~~open-access ~~other~~transportation ~~matters~~service, ~~primarily~~contain bystrict limits on the ~~Federal~~means ~~Energy~~by ~~Regulatory~~which ~~Commission~~a ~~(“FERC”).~~shipper ~~The~~releases ~~intrastate~~its ~~transportation,~~pipeline ~~local~~capacity ~~distribution~~to ~~and~~another ~~retail~~potential ~~sale~~shipper, ofwhich ~~natural~~provisions ~~gas~~include ~~generally~~FERC’s ~~are~~“shipper-must-have-title” rule. ~~subject~~Violations toby ~~state~~a ~~regulation~~shipper (i.e., ~~FERC’s~~a ~~regulations~~pipeline ~~for~~customer) ~~interstate~~of ~~natural~~FERC’s ~~gas~~capacity ~~transmission~~release inrules ~~some~~or ~~circumstances~~shipper-must-have-title ~~may~~rule ~~also~~could subject ~~affect~~a ~~the~~shipper ~~intrastate~~to ~~transportation~~substantial ofpenalties ~~natural~~from ~~gas~~FERC.

FERC also ~~regulates~~authorizes the ~~rates,~~construction ~~terms~~ and ~~conditions~~operation ~~applicable~~of interstate natural gas pipelines under Section 7 of the NGA. With respect to its review of applications for the ~~interstate~~construction ~~transportation~~and operation of interstate natural gas bypipeline ~~pipelines~~facilities under the ~~Natural~~NGA, ~~Gas~~FERC ~~Act~~must ~~(“NGA”)~~comply aswith environmental ~~well~~review asrequirements ~~under~~of ~~Section~~NEPA. ~~311~~In 2021, in an individual pipeline certificate proceeding, FERC announced that, upon reconsideration of its prior position, it will assess the ~~Natural~~significance ~~Gas~~of ~~Policy~~a ~~Act~~proposed pipeline project’s GHG emissions and those emissions’ contribution to climate change in fulfilling its obligations under NEPA. In 2022, FERC issued a nonbinding draft GHG policy statement that would have encouraged project applicants to disclose a project’s reasonably foreseeable GHG emissions and stipulated that projects that would exceed 100,000 tons of ~~1978~~GHG emissions would require an environmental impact statement. However, the Trump administration withdrew the GHG policy statement in January 2025.

~~Under FERC’s current regulatory regime, interstate~~ Wellhead natural gas ~~transportation~~sale ~~services~~prices ~~must~~are beunregulated. ~~provided~~Sales onof ancondensate ~~open-access,~~and ~~non-discriminatory~~natural ~~basis~~gas atliquids ~~cost-based~~are ~~rates~~not orcurrently atregulated ~~market-based~~and ~~rates~~are ifmade ~~the transportation market~~ at ~~issue is sufficiently competitive~~market prices. ~~Among~~The ~~other~~Partnership ~~things,~~cannot ~~the~~predict ~~FERC-regulated~~whether ~~tariffs,~~new ~~under~~legislation ~~which~~to ~~interstate~~regulate ~~pipelines~~natural ~~provide~~gas ~~such~~might ~~open-access~~be ~~transportation service~~proposed, ~~contain~~what ~~strict~~proposals, ~~limits~~if onany, ~~the~~might actually ~~means~~be enacted by ~~which~~Congress aor ~~shipper~~the ~~releases~~various ~~its~~state ~~pipeline~~legislatures, ~~capacity~~and towhat ~~another~~effect, ~~potential~~if ~~shipper~~any, ~~which~~the ~~provisions~~proposals ~~include~~might ~~FERC’s “shipper-must-~~have~~-title”~~ ~~rule.~~on ~~Violations~~the ~~by a shipper (i.e., a pipeline customer)~~ operations of ~~FERC’s~~the ~~capacity~~properties ~~release~~the ~~rules~~Partnership ~~or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC~~owns.

~~FERC~~Sales of ~~also authorizes~~ the ~~construction~~Partnership’s oil and ~~operation of interstate~~ natural gas ~~pipelines~~liquids ~~under~~are ~~Section~~also 7affected ofby the ~~NGA.~~availability, ~~With~~terms ~~respect~~and tocosts ~~its~~of ~~review~~transportation. ofThe rates, ~~applications~~terms, ~~for~~and ~~the~~conditions ~~construction~~applicable ~~and~~to ~~operation~~the interstate transportation of ~~interstate~~oil and natural gas ~~pipeline~~liquids ~~facilities~~by ~~under~~pipelines ~~the~~are ~~NGA,~~regulated by the FERC ~~must~~under ~~comply~~the ~~with~~Interstate ~~environmental~~Commerce ~~review~~Act ~~requirements of NEPA~~(“ICA”). InThe ~~2021,~~ FERC ~~issued~~has implemented a ~~Notice~~simplified ofand ~~Inquiry~~generally ~~(NOI)~~applicable ~~requesting~~ratemaking methodology ~~public~~for ~~comment~~interstate onoil ~~whether~~and itnatural ~~should~~gas ~~revise~~liquids ~~its~~pipelines ~~approach~~to ~~under~~fulfill ~~its~~the ~~current~~requirements ~~policy~~of ~~statement~~Title onXVIII ~~certification~~ of ~~new~~the ~~natural~~Energy ~~gas~~Policy ~~transportation~~Act of ~~facilities,~~1992 ~~including~~comprised ~~among~~of ~~other~~an ~~things,~~indexing ~~options~~system ~~for~~to ~~assessing~~establish ~~the~~ceilings ~~significance~~on ofinterstate ~~the~~oil ~~impacts~~and ofnatural ~~greenhouse~~ gas ~~(GHG)~~liquids ~~emissions~~pipeline rates. ~~This~~In ~~NOI~~2017, isFERC issued ~~pending~~a ~~before~~declaratory ~~FERC.~~holding ~~Also~~that incertain ~~2021,~~arrangements inbetween an ~~individual~~oil pipeline ~~certificate~~and ~~proceeding,~~its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC ~~announced~~held that, ~~upon~~providing ~~reconsideration~~transportation ofservice ~~its~~to ~~prior~~affiliates ~~position,~~at itwhat ~~will~~is ~~assess~~essentially the ~~significance~~variable cost of athe ~~proposed~~movement, ~~pipeline~~while ~~project’s~~requiring ~~GHG~~non-affiliated ~~emissions~~shippers ~~and~~to ~~those~~pay ~~emissions’~~the ~~contribution~~(higher) tofiled ~~climate~~tariff ~~change~~rate, inwould ~~fulfilling~~violate ~~its~~the ~~obligations~~ICA. ~~under~~In ~~NEPA~~2022, FERC denied a rehearing of this order.

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.17

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.Index

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.

19Exports of US Oil Production and Natural Gas Production

~~Index~~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. In January 2024, the Biden Administration paused approvals for pending and future applications to export LNG from new projects while the DOE reviews the economic and environmental impacts of those projects. In January 2025, the second Trump Administration rescinded this pause in approvals, and in February 2025, has begun to issue LNG export licenses.

~~Exports of US Oil Production and Natural Gas Production~~Other Regulation

AtIn addition ~~the~~to ~~end of 2015,~~ the ~~U.S.~~regulation ~~Congress voted to end a decades-old prohibition~~ of ~~exports of~~ oil ~~produced~~and ~~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~~pipeline ~~exports~~transportation ~~of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico and Canada. Under the NGA~~rates, ~~FERC authorizes~~ the ~~construction~~oil and ~~operation of~~ natural gas ~~pipeline~~industry ~~facilities~~generally ~~crossing~~is ~~the U.S. border used~~ subject to ~~export~~compliance ~~U.S.-produced~~with ~~natural~~various ~~gas.~~other ~~In addition~~federal, ~~under~~state ~~the NGA, the DOE authorizes the export of liquefied natural gas (“LNG”) through LNG export facilities, while FERC authorizes the siting~~ and ~~construction~~local ofregulations ~~onshore~~ and ~~near-shore LNG export terminals~~laws. InSome ~~2020, DOE issued a Final Policy Statement discontinuing its practice~~ of ~~granting~~those alaws ~~standard~~relate ~~20-year export term for long-term authorizations~~ to ~~export~~occupational 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”)safety, resource conservation and ~~adopting~~equal aemployment ~~term through December 31, 2050, as the standard export term for long-term Non-FTA authorizations~~opportunity. ~~Under~~The ~~DOE’s~~Partnership ~~Policy~~does ~~Statement,~~not ~~holders~~believe ofthat ~~existing~~compliance ~~Non-FTA authorizations may file an application~~ with ~~DOE~~these ~~requesting~~laws towill ~~amend~~have ~~its~~a ~~authorization~~material adverse toeffect ~~extend~~upon its ~~export term through December 31, 2050~~operations. In January 2024, the Biden Administration paused approvals for pending and future applications to export LNG from new projects while the DOE reviews the economic and environmental impacts of those projects.

~~Other Regulation~~Employees

InThe Partnership ~~addition~~has tono officers, directors or employees. Instead, the ~~regulation~~General Partner manages the day-to-day affairs of ~~oil~~the Partnership, and ~~natural~~all ~~gas~~decisions ~~pipeline~~regarding ~~transportation~~the ~~rates,~~management of the ~~oil~~Partnership are made by the General Partner and ~~natural~~its ~~gas~~officers. ~~industry~~The ~~generally~~General isPartner ~~subject~~utilizes the toservices ~~compliance~~of ~~with~~qualified ~~various~~third ~~other~~parties ~~federal~~and consultants for specific projects, ~~state~~such ~~and~~as ~~local~~the ~~regulations~~preparation ~~and~~of ~~laws~~the Partnership’s reserve estimates. ~~Some~~The Board of ~~those~~Directors ~~laws~~of ~~relate~~the toGeneral ~~occupational~~Partner ~~safety~~does not receive any salary, ~~resource~~bonus ~~conservation~~or ~~and~~consulting ~~equal~~fees ~~employment~~for ~~opportunity.~~serving ~~The~~on ~~Partnership~~the ~~does~~board of ~~not~~directors. ~~believe~~For ~~that~~more ~~compliance~~detail, ~~with~~refer ~~these~~to ~~laws~~Part ~~will~~III, ~~have~~Items a10, ~~material~~11 ~~adverse~~and ~~effect~~13, ~~upon~~respectively, ~~its~~of ~~operations~~this Form 10-K.

~~Employees~~General Corporate Information

~~The~~Energy Resources ~~Partnership~~12, ~~has~~L.P. nois ~~officers,~~a ~~directors~~Delaware orlimited ~~employees.~~partnership ~~Instead,~~founded ~~the~~in ~~General~~2016 ~~Partner~~with ~~manages~~principal ~~the~~offices ~~day-to-day~~at ~~affairs~~120 ofW ~~the~~3rd ~~Partnership~~Street, ~~and~~Suite ~~all~~220, ~~decisions~~Fort ~~regarding~~Worth, Texas ~~the~~76102. ~~management~~The ofPartnership ~~the~~can ~~Partnership~~be ~~are~~reached ~~made~~at by(817) 882-9192 and the ~~General~~Partnership ~~Partner~~website ~~and~~address ~~its~~is ~~officers~~www.energyresources12.com. The ~~General~~Partnership makes ~~Partner~~available, ~~utilizes~~free ~~the~~of ~~services~~charge ofthrough ~~qualified~~its ~~third~~Internet ~~parties~~website, its annual report on Form 10-K and ~~consultants~~quarterly ~~for~~reports ~~specific~~on ~~projects~~Form 10-Q, ~~such~~and amendments asto ~~the~~those ~~preparation~~reports offiled ~~the~~or ~~Partnership’s~~furnished ~~reserve~~pursuant ~~estimates.~~to ~~The~~section ~~Board~~13(a) ofor ~~Directors~~15(d) of the ~~General~~Securities ~~Partner~~Exchange ~~does~~Act ~~not~~of ~~receive~~1934, ~~any~~as ~~salary~~amended, as ~~bonus~~soon oras ~~consulting~~reasonably ~~fees~~practicable ~~for~~after ~~serving on~~ the ~~board~~Partnership ofelectronically ~~directors.~~files ~~For~~such ~~more~~material ~~detail~~with, ~~refer~~or tofurnishes ~~Part~~it ~~III~~to, ~~Items~~the ~~10,~~SEC. 11Information contained ~~and~~on ~~13,~~the ~~respectively,~~Partnership’s ofwebsite ~~this~~is ~~Form~~not ~~10-K~~incorporated by reference into this report.

~~General Corporate Information~~18

Energy Resources 12, L.P. is a Delaware limited partnership founded in 2016 with principal offices at 120 W 3rd Street, Suite 220, Fort Worth, Texas 76102. The Partnership can be reached at (817) 882-9192 and the Partnership website address is www.energyresources12.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.Index

20Item 1A. Risk Factors

~~Index~~Risks Related to the Partnership’s Business, Results of Operations and Cash Flows

~~Item~~If oil, ~~1A.~~natural ~~Risk~~gas ~~Factors~~or other hydrocarbon prices decrease and remain depressed for a prolonged period, cash flows from operations will decline and cash available for distributions will be impacted.

~~Risks~~The Partnership’s ~~Related~~revenue, toprofitability and cash flow depend upon the prices for oil, natural gas and other hydrocarbons. The prices the Partnership receives for its production will be volatile and a drop in prices can significantly affect its financial results and adversely affect the Partnership’s ~~Business~~ability to obtain credit, ~~Results~~maintain its borrowing capacity and to repay indebtedness, all of which ~~Operations~~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 ~~Cash~~on ~~Flows~~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:

If● the domestic and foreign supply of and demand for oil, and natural gas and other hydrocarbons; ● regulations which may prevent or limit the export of oil, natural gas and other ~~hydrocarbon~~hydrocarbons; ~~prices~~● ~~decrease~~the amount of added production from development of unconventional natural gas reserves; ● the price and ~~remain~~quantity ~~depressed~~of ~~for~~foreign aimports ~~prolonged~~of ~~period~~oil, natural gas and other hydrocarbons; ● the level of consumer product demand; ● adverse weather conditions, natural disasters and global health concerns, such as the ~~period~~COVID-19 ~~experienced~~coronavirus outbreak in early 2020; ~~upon~~● domestic and foreign governmental regulations, including environmental initiatives and taxation; ● overall domestic and global economic conditions; ● the ~~onset~~value of the ~~COVID-19~~U.S. ~~pandemic~~dollar relative to the currencies of other countries; ● political and economic conditions and events in foreign oil and natural gas producing countries, ~~cash~~including ~~flows~~embargoes, ~~from~~continued ~~operations~~hostilities ~~will~~in ~~decline~~the Middle East and ~~cash~~other ~~available~~sustained ~~for~~military ~~distributions~~campaigns, ~~will~~conditions bein ~~impacted~~South America, Central 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; ● the proximity and capacity of natural gas pipelines and other transportation facilities to the Partnership’s production; ● technological advances affecting energy consumption; ● price and availability of competitors’ supplies of oil and natural gas; ● speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts; ● the price and availability of alternative fuels; and ● the impact of energy conservation efforts.

~~The~~Decreased ~~Partnership’s revenue~~oil, ~~profitability~~natural gas and ~~cash~~other ~~flow~~hydrocarbon ~~depend~~prices will ~~upon~~decrease Partnership revenues, and may also reduce the ~~prices~~amount ~~for~~of oil, natural gas ~~and~~or other hydrocarbons. ~~The~~that ~~prices~~ the Partnership ~~receives~~can economically ~~for~~produce. ~~its~~If ~~production~~decreases ~~will~~occur, beor ~~volatile~~if ~~and~~estimates aof ~~drop~~development incosts ~~prices~~increase, ~~can~~production ~~significantly~~data ~~affect~~factors ~~its~~change ~~financial~~or drilling results deteriorate, ~~and~~accounting ~~adversely~~rules ~~affect~~may require the Partnership’s ~~ability~~ to ~~obtain~~write ~~credit~~down, ~~maintain~~as ~~its~~a ~~borrowing~~non–cash ~~capacity~~charge ~~and~~ to ~~repay indebtedness~~earnings, ~~all~~the carrying value of its ~~which~~oil ~~can~~and ~~affect~~natural ~~the~~gas properties for impairments. The Partnership’s ~~ability~~is required to ~~pay~~perform ~~distributions.~~impairment ~~Changes~~tests on its assets whenever events or changes in ~~prices~~circumstances ~~have~~lead to a ~~significant~~reduction ~~impact~~of on the ~~value~~estimated ofuseful life or estimated future cash flows that would indicate that the carrying ~~Partnership~~amount may not be recoverable or whenever management’s ~~reserves~~plans ~~and~~change onwith ~~its~~respect ~~cash~~to ~~flows~~those assets. ~~Prices~~The Partnership may ~~fluctuate~~incur impairment ~~widely~~charges in ~~response~~the tofuture, ~~relatively~~which ~~minor~~could ~~changes~~have a material adverse effect on its results of operations in ~~supply~~the period taken and ~~demand,~~the Partnership’s ~~market~~ability ~~uncertainty~~to ~~and~~borrow afunds ~~variety~~under ofthe ~~additional~~Credit ~~factors~~Facility, ~~that~~which ~~are~~may ~~beyond~~adversely affect the Partnership’s ~~control,~~ability ~~such~~to ~~as:~~make cash distributions to holders of its common units and service its debt obligations.

●The Partnership ~~the domestic and foreign supply of and demand for oil and natural gas and other hydrocarbons; ● regulations which~~ may ~~prevent~~not orhave ~~limit~~sufficient ~~the~~cash ~~export~~from ofoperations ~~oil,~~following ~~natural gas and other hydrocarbons; ●~~ the ~~amount~~establishment of ~~added~~cash ~~production from development of unconventional natural gas~~ reserves; ~~● the price~~ and ~~quantity~~payment of ~~foreign~~fees ~~imports of oil, natural gas~~ and ~~other hydrocarbons; ● the level of consumer product demand; ● adverse weather conditions~~expenses, ~~natural disasters and global health concerns, such as the COVID-19 coronavirus outbreak in early 2020; ● domestic and foreign governmental regulations,~~ including ~~environmental~~cost ~~initiatives~~reimbursements and ~~taxation;~~management ●fees ~~overall domestic and global economic conditions; ● the value of the U.S. dollar relative~~ to the ~~currencies~~General ~~of other countries; ● political and economic conditions and events in foreign oil and natural gas producing countries~~Partner, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage; ● the ability of members of the Organization of Petroleum Exporting Countries to ~~agree~~enable ~~to and maintain oil price and production controls; ●~~ the ~~proximity~~Partnership ~~and capacity of natural gas pipelines and other transportation facilities~~ to ~~the~~make ~~Partnership’s~~cash ~~production;~~distributions ~~● technological advances affecting energy consumption; ● price and availability of competitors’ supplies of oil and natural gas; ● speculation as~~ to ~~the future price~~ holders of ~~oil~~its ~~and~~common ~~natural~~units ~~gas~~under ~~and~~its ~~the~~cash ~~speculative~~distribution ~~trading of oil and natural gas futures contracts; ● the price and availability of alternative fuels; and ● the impact of energy conservation efforts~~policy.

~~Decreased oil, natural gas and other hydrocarbon prices will decrease~~ The Partnership ~~revenues, and~~ may ~~also~~not ~~reduce~~have ~~the~~sufficient ~~amount~~available ofcash ~~oil,~~each ~~natural~~month ~~gas~~to orenable ~~other~~it 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~~make ~~down, as a non–~~cash ~~charge~~distributions to ~~earnings,~~ the ~~carrying~~holders ~~value~~ of ~~its~~common ~~oil and natural gas properties for impairments~~units. The ~~Partnership~~amount ~~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~~can ~~incur~~distribute ~~impairment charges in the future, which could have a material adverse effect~~ on its ~~results~~common ofunits ~~operations~~principally independs upon the ~~period~~amount ~~taken~~of ~~and~~cash the Partnership’s ~~ability~~generates from toits ~~borrow funds under a credit facility~~operations, which ~~may~~will ~~adversely~~fluctuate ~~affect~~from ~~the~~month ~~Partnership’s ability~~ to ~~make~~month ~~cash~~based ~~distributions~~on, toamong ~~holders~~other ~~of its common units and service its debt obligations.~~things:

~~The~~● ~~Partnership may not have sufficient cash from operations following~~ the ~~establishment~~amount of ~~cash~~oil, ~~reserves~~natural ~~and~~gas ~~payment of fees~~ and ~~expenses,~~natural ~~including~~gas ~~cost~~liquids ~~reimbursements~~the ~~and~~Partnership ~~management~~produces; ~~fees~~● to the ~~General~~prices ~~Partner,~~at towhich ~~enable~~ the Partnership tosells ~~make~~its ~~cash~~production; ~~distributions~~● tothe ~~holders~~Partnership’s ofability ~~its~~to ~~common~~hedge ~~units~~commodity ~~under~~prices ~~its~~at ~~cash~~economically ~~distribution~~attractive ~~policy.~~prices;

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:19

● 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 fees and 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.Index

21● 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 fees and 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.

~~Index~~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:

In● ~~addition,~~ the ~~actual~~ amount of cash reserves established by the ~~Partnership~~General ~~will~~Partner ~~have~~for ~~available~~the proper conduct of the Partnership’s business and for ~~distribution~~capital expenditures, which may be substantial; ● the operator(s) of the Partnership’s properties will ~~depend~~control the timing of any capital expenditures necessary to drill or overhaul any wells on ~~other~~the ~~factors,~~properties ~~some~~the Partnership invests in; ● the cost of ~~which~~operations, ~~are~~infrastructure ~~beyond~~and drilling; ● the Partnership’s ~~control~~debt service requirements and other liabilities, ~~including:~~if the Partnership increases debt levels; ● 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 ~~the~~result ~~amount~~ of ~~cash~~these ~~reserves~~factors, ~~established by~~ the ~~General~~amount ~~Partner for the proper conduct~~ of ~~the~~cash ~~Partnership’s business and for capital expenditures, which may be substantial; ●~~ the ~~operator(s) of the~~ Partnership’s ~~properties~~distributes ~~will control the timing of any capital expenditures necessary~~ to ~~drill~~holders ~~or overhaul any wells on the properties the Partnership invests in; ● the cost~~ of ~~operations,~~its ~~infrastructure~~common ~~and~~units ~~drilling;~~may ●fluctuate ~~the~~significantly from ~~Partnership’s~~month ~~debt service requirements and other liabilities, if the Partnership increases debt levels; ● 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~~month.

AsThe Partnership ahas ~~result~~limited ofcontrol ~~these~~over ~~factors,~~ the ~~amount~~activities ofon ~~cash the Partnership distributes to holders of~~ its ~~common units may fluctuate significantly from month to month~~properties.

Thirteen other companies operate the properties the Partnership has acquired. The Partnership has limited ability to influence or control ~~over~~the operation or future development of these non-operated properties or the ~~activities~~amount of capital expenditures that it is required to fund. The failure of an operator of the Partnership’s wells 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 the operator and other working interest owners for these projects and its 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.

~~Thirteen other companies operate the properties the Partnership has acquired.~~ The Partnership ~~has~~participates limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that it is required to fund. The failure of an operator of the Partnership’s wells to adequately perform operations, to comply with the applicable agreements or to act in ~~ways~~oil ~~that are in the Partnership’s best interest could reduce the Partnership’s production~~ and ~~revenues.~~natural ~~The~~gas ~~Partnership’s~~leases ~~dependence~~with third onparties ~~the~~who ~~operator~~may ~~and~~not ~~other~~be ~~working~~able ~~interest~~to ~~owners~~fulfill ~~for~~their ~~these~~commitments ~~projects and its 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~~projects.

The Partnership owns less than 100% of the working interest in the Bakken 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. The Partnership ~~participates~~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 ~~gas~~NGL ~~leases~~prices ~~with~~may ~~third~~increase ~~parties~~the ~~who~~likelihood ~~may~~that ~~not~~some beof these working interest owners, particularly those that are smaller and less established, are not able to fulfill their ~~commitments~~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 ~~projects~~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 ~~owns~~results less than 100% of the working interest in the Bakken 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. 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~~operations ~~actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices~~ may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. Another working interest owner may be ~~unable~~impacted orby ~~unwilling~~a tolack ~~pay its share~~ of ~~project~~geographical ~~costs, and, in some cases, may declare bankruptcy~~diversification. 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~~All of the Partnership’s ~~results~~assets ~~from~~are ~~operations~~located in concentrated areas of the Bakken shale in neighboring counties in 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 afactors ~~lack~~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 ~~geographical~~regional ~~diversification~~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.

All of the Partnership’s assets are located in concentrated areas of the Bakken shale in neighboring counties in 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~~depends beon ~~disproportionately~~oil ~~exposed to the effects of regional supply~~ and ~~demand~~natural ~~factors,~~gas ~~delays or interruptions of production from wells in this area caused by governmental regulation, processing or~~ transportation ~~capacity~~and ~~constraints, market limitations, weather events or interruption of the~~ processing orfacilities ~~transportation of oil or natural gas. Additionally, the Partnership may be exposed to further risks, such as changes in field-wide rules~~ and ~~regulations~~other assets that ~~could~~are ~~cause~~owned ~~the~~by ~~Partnership~~third ~~to permanently or temporarily shut-in all of its wells within the Williston Basin~~parties. ~~The Partnership does not currently intend to broaden the geographic scope of its asset base.~~

The marketability of Partnership ~~depends on~~ oil and natural gas ~~transportation~~depends in part on the availability, proximity and ~~processing~~capacity of pipeline systems, processing facilities, ~~and~~oil ~~other~~trucking ~~assets~~fleets ~~that~~and ~~are~~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 Bakken Assets. The negative effects arising from these and similar circumstances may last for an extended period of time.

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 Bakken Assets. The negative effects arising from these and similar circumstances may last for an extended period of time.20

22Index

~~Index~~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 (“Army Corps”) 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 Army Corps 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. In September 2023, the Army Corps released an initial draft of its environmental impact statement that outlined possible outcomes and alternatives to the use of DAPL, and opened up a public comment period. No date has been set for the release of the Army Corps’ final report, although it is expected in 2025. 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.

~~The~~Any significant ~~Dakota~~curtailment ~~Access~~in ~~Pipeline~~gathering ~~(“DAPL”),~~system aor ~~major~~ pipeline ~~running out of the Williston Basin~~capacity, isor ~~subject to publicized ongoing litigation that could threaten its continued operation. In July 2020,~~ the ~~U.S.~~unavailability 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.~~sufficient Inthird-party ~~August~~trucking ~~2020,~~or ~~the~~rail ~~ruling was stayed on appeal by the U.S. Court of Appeals for the D.C. Circuit (“D.C. Appellate Court”)~~capacity, could ~~allowing~~adversely ~~the~~affect ~~pipeline to operate until a further ruling was made. In January 2021,~~ the ~~D.C. Appellate Court affirmed the D.C. District Court~~Partnership’s ~~decision.~~results ~~Further, in May 2021, the D.C. District Court denied an injunction that would have required a shutdown~~ of ~~the~~operations Dakota Access Pipeline while the U.S. Army Corps of Engineers (“Army Corps”) completes its comprehensive environmental review. In June 2021, the D.C. District Court dismissed the existing claims against the Dakota Access Pipeline and ~~its~~financial ~~operators, but stated the plaintiffs could renew challenges against the pipeline after the Army Corps releases its environmental review report~~condition. 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. In September 2023, the Army Corps released an initial draft of its environmental impact statement that outlined possible outcomes and alternatives to the use of DAPL, and opened up a public comment period through December 2023. No date has been set for the release of the Army Corps’ final report. 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~~The Partnership ~~significant~~and ~~curtailment~~the inoperators ~~gathering~~of ~~system~~its orproperties ~~pipeline~~may ~~capacity,~~encounter orobstacles to marketing the ~~unavailability~~Partnership’s share of ~~sufficient~~oil, natural ~~third-party~~gas ~~trucking~~and orother ~~rail capacity~~hydrocarbons, which could adversely ~~affect~~impact the Partnership’s ~~results of operations and financial condition~~revenues.

The marketability of the Partnership’s ~~and~~production will depend upon numerous factors beyond the ~~operators~~Partnership’s control, including the availability and capacity of ~~its~~natural ~~properties~~gas ~~may~~gathering ~~encounter~~systems, ~~obstacles~~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 ~~share~~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 ~~hydrocarbons~~discussed above. The availability of markets is beyond the Partnership’s control. If market factors dramatically change, the ~~which~~impact on the Partnership’s revenues could be substantial and could adversely ~~impact~~affect the Partnership’s ~~revenues~~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 any Partnership debt obligations.

The ~~marketability of the~~ Partnership’s ~~production~~may ~~will~~be ~~depend~~required ~~upon~~to ~~numerous~~shut-in ~~factors~~wells ~~beyond~~or ~~the~~delay ~~Partnership’s~~initial ~~control,~~production ~~including~~for ~~the~~lack ~~availability and capacity~~ of ~~natural~~a ~~gas~~viable ~~gathering~~market ~~systems,~~or ~~pipelines~~because ~~and~~of ~~other transportation and processing facilities owned by third parties. Transportation space on~~ the ~~gathering~~inadequacy ~~systems and pipelines the Partnership expects to utilize is occasionally limited~~ or unavailability ~~unavailable~~of ~~due~~pipeline, togathering ~~repairs~~system, orprocessing, ~~improvements~~treating, tofractionation ~~facilities~~ or ~~due~~refining tocapacity. ~~space~~When ~~being utilized by other companies~~ that ~~have~~occurs, ~~priority transportation agreements. The Partnership’s access to transportation and processing options and~~ the ~~marketing of the~~ Partnership’s will ~~production can also~~ be ~~affected~~unable byto ~~U.S.~~realize ~~federal~~revenue ~~and~~from ~~state~~such ~~regulation~~wells ofuntil ~~oil and natural gas production and transportation, as well as~~ the ~~other~~inadequacy ~~risks~~or ~~discussed~~unavailability ~~above. The availability of markets~~ is ~~beyond the Partnership’s control~~remedied. IfThis ~~market~~can ~~factors~~result ~~dramatically~~in ~~change,~~considerable delays ~~the~~from ~~impact on~~ the ~~Partnership’s~~initial ~~revenues~~discovery ~~could~~of bea ~~substantial~~reservoir ~~and~~to ~~could adversely affect~~ the ~~Partnership’s~~actual ~~ability~~production toof ~~produce~~the ~~and market~~ oil, ~~natural gas~~ and natural gas ~~liquids,~~and ~~the~~realization ~~value~~ of ~~the Partnership’s common units and the Partnership’s ability to pay distributions on the Partnership’s common units and service any Partnership debt obligations~~revenues.

The Partnership may beneed ~~required~~additional tofunding ~~shut-~~in ~~wells~~order 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~~retain ~~revenue~~its ~~from~~full ~~such~~interest ~~wells until the inadequacy or unavailability is remedied. This can result~~ in ~~considerable delays from~~ the ~~initial~~Bakken ~~discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues~~Assets.

The Partnership anticipates that it may be obligated to significantly invest within the next five years in drilling and well completion capital expenditures to fully participate in operator drilling programs in the Bakken 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 may ~~need~~require additional ~~funding~~financing into ~~order~~fund the anticipated capital expenditures needed to retain its full interest in the Bakken Assets. None of these funding sources is guaranteed, and if the Partnership is unable to obtain all of this funding, the Partnership may lose all or a portion of the assets acquired or reduce distributions, and its results of operations will be negatively affected accordingly.

~~The~~Property interests ~~Partnership anticipates~~ that ~~it may be obligated to significantly invest within~~ the next five years in drilling and well completion capital expenditures to fully participate in operator drilling programs in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements governing those properties. The Partnership ~~will~~has ~~depend,~~purchased ~~at least in part, on cash flow from operations and/~~or ~~may~~of ~~require~~which ~~additional financing to fund~~ the ~~anticipated~~Partnership ~~capital~~participates ~~expenditures needed to retain its full interest~~ in the ~~Bakken~~development ~~Assets.~~may ~~None~~not ofproduce ~~these~~as ~~funding sources is guaranteed,~~ projected and if the Partnership ismay be unable to ~~obtain~~realize ~~all~~reserve ~~of this funding~~potential, ~~the~~which ~~Partnership~~could ~~may~~adversely ~~lose~~affect ~~all or a portion of~~ the ~~assets~~Partnership’s ~~acquired~~cash available orfor ~~reduce distributions, and its results of operations will be negatively affected accordingly~~distribution.

23The 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 natural 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 natural 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.

~~Index~~21

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.Index

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, Additional potential ~~environmental~~risks ~~hazards,~~at ~~potential tax and ERISA liabilities, and other liabilities and similar factors. Reserve estimates may be prepared by~~ the ~~operators~~acquisition ordate ~~third parties for the operators of properties. The Partnership has engaged~~ and ~~may~~those ~~engage~~related ~~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~~include, ~~and~~among ~~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.things:

~~Additional~~● ~~potential~~incorrect ~~risks~~assumptions atregarding the ~~acquisition~~future ~~date~~prices of oil, natural gas and ~~those~~other ~~related~~hydrocarbons toor the future operating or development ~~include~~costs of properties; ● incorrect estimates of the reserves and projected development results attributable to a property the Partnership owns; ● drilling, ~~among~~operating and other ~~things:~~cost overruns by the operator of the properties; ● 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.

●Compliance with ~~incorrect~~financial ~~assumptions regarding the future prices of oil, natural gas~~ and other ~~hydrocarbons~~covenants orin 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 by the operator of the properties; ● an inability to integrate successfully the properties the Partnership has acquired; ● the assumption of liabilities; ● the diversion of management’s ~~attention~~existing ~~from~~or ~~other~~future ~~business~~debt ~~concerns;~~agreements ~~and~~may ●reduce ~~losses~~operational offlexibility ~~key~~and create ~~employees~~default risk.

The Partnership’s ~~has~~existing ~~experienced~~indebtedness ~~higher~~contains, and ~~costs~~indebtedness that the Partnership may enter into in ~~2022~~the future likely will contain, customary covenants that may restrict the Partnership’s operations and ~~2023~~restrict ~~due~~its ability to ~~inflation~~make ~~having~~distributions ~~widespread~~to ~~effects~~holders onof ~~the~~its ~~economy~~common units. ~~Sustained~~The ~~periods~~Partnership’s offailure ~~higher~~to ~~costs~~comply with the covenants in its existing or future indebtedness, or its inability to make required principal and interest payments, could ~~reduce~~cause a default under the ~~Partnership’s~~applicable ~~profitability~~debt agreement, which could result in increased interest rates and ~~cash~~the ~~flow~~acceleration of the debt, requiring the Partnership to repay such debt with capital obtained from other sources, which may not be available to the Partnership or may only be available on unfavorable terms. In addition, if the Partnership defaults on its existing indebtedness, its lender may take possession of the portion of the Bakken Assets securing such debt.

~~Historically,~~The Partnership ~~capital~~experienced ~~and~~higher ~~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~~2023 ~~cost~~due ofto ~~electricity,~~inflation ~~tubular~~having ~~goods,~~widespread ~~water,~~effects ~~sand~~on ~~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~~economy. ~~Historically,~~Sustained ~~oil~~periods ~~and natural gas prices have fluctuated resulting in fluctuating levels~~ of ~~drilling~~higher ~~activity in the U.S. oil and natural gas industry. Lower prices typically lead to lower~~ costs could ofreduce 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.

~~Any~~Historically, capital ~~future~~and ~~hedging~~operating ~~transactions~~costs intypically ~~which~~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 ~~elects~~control toas ~~engage~~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 ~~expose~~rely itupon, 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 ~~counterparty~~lower ~~credit~~costs ~~risk~~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.

~~Historically,~~Any future ~~the Partnership has engaged in~~ hedging transactions toin ~~reduce,~~which ~~but not eliminate,~~ the ~~effect of volatility in oil, gas and other hydrocarbon prices. The~~ Partnership ~~may~~elects ~~also~~to engage ~~in hedging transactions in future periods. Hedging transactions~~ will expose ~~the~~it ~~Partnership~~ to ~~risk of financial loss if a~~ counterparty ~~fails~~credit ~~to perform under a derivative contract. The~~ risk ~~of counterparty non-performance is of particular concern when there are disruptions in the financial markets and there are significant declines in oil and natural gas prices~~. Either of these events could lead to sudden changes in a counterparty’s liquidity and 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, the Partnership’s ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of the Partnership’s hedge providers or some other similar proceeding or liquidity constraint might make it unlikely that the Partnership would be able to collect all or a significant portion of amounts owed to it by the distressed entity or entities.

~~During~~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 ~~falling~~financial ~~commodity~~loss if a counterparty fails to perform under a derivative contract. The risk of counterparty non-performance is of particular concern when there are disruptions in the financial markets and there are significant declines in oil and natural gas prices. Either of these events could lead to sudden changes in a counterparty’s liquidity and impair its ability to perform under the terms of the derivative contract. The Partnership is unable to predict sudden changes in a counterparty’s ~~hedge~~creditworthiness ~~receivable~~or ~~positions~~ability to ~~increase,~~perform. ~~which~~Even ~~increases~~if the Partnership does accurately predict sudden changes, the Partnership’s ~~exposure~~ability to negate the risk may be limited depending upon market conditions. IfFurthermore, the ~~creditworthiness~~bankruptcy of one or more of the Partnership’s ~~counterparties~~hedge ~~deteriorates~~providers ~~and~~or ~~results~~some other insimilar ~~their~~proceeding ~~nonperformance,~~or liquidity constraint might make it unlikely that the Partnership ~~could~~would ~~incur~~be able to collect all or a significant portion ~~loss~~of amounts owed to it by the distressed entity or entities.

24Hedging 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.

~~Index~~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.

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.22

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.Index

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 future 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 prices at which the Partnership hedges its production 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 hedges may not fully protect it from significant declines in oil and natural gas prices received for its future production. Conversely, the Partnership’s hedges 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 to previous 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 and well completion are unsuccessful, the Partnership’s cash available for distributions and financial condition will be adversely affected.

The Partnership has acquired oil and ~~gas~~natural gas properties that are not fully developed and require that the Partnership engage in drilling and well completion to fully exploit the reserves attributable to the properties. Because the Partnership has acquired non-operated properties, it will not be in charge of the drilling and well completions but will be obligated to pay its pro rata share of drilling and completion costs or be subject to penalties. Drilling and completion of wells 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.

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. Overall drilling success rates 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 the Partnership’s operations and financial condition by reducing its available cash and resources.

25The Partnership’s continued success depends upon its ability to develop oil and natural gas reserves that are economically recoverable.

~~Index~~In addition, the Partnership’s future oil and natural gas production will depend on its success in 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 or 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 continued success depends upon its ability to develop oil and gas reserves that are economically recoverable.~~23

In addition, the Partnership’s future oil and natural gas production will depend on its success in 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 or 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.Index

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 any ~~future~~ 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 operators of the properties maintain 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 any ~~future~~ 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 and McKenney, the chief executive officer and chief financial officer. The loss of the services of one or more of these key employees could have a material adverse effect on the Partnership. Neither the General Partner nor the Partnership maintains key-man life insurance with respect to any employees. The Partnership’s business will also be dependent upon its ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause the Partnership to incur greater costs or prevent it from pursuing its acquisition and development strategy as quickly as the Partnership would otherwise wish to do.

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

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

26Distributions 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.

~~Index~~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.

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.24

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 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 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.Index

~~Despite terminating a credit facility in November 2019~~Moreover, ~~the Partnership may enter into~~ a ~~new~~portion ~~credit~~of ~~facility in~~ the ~~future, which would require the~~ Partnership’s ~~to use a portion of its~~ cash flow may be used to pay interest on the Credit Facility. Interest and principal ofpayments ~~any~~on ~~indebtedness~~the ~~when~~Credit ~~due,~~Facility ~~which~~ will reduce the cash available to finance the Partnership’s operations and other business activities. ~~This~~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 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 is 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 competition for the General Partner’s time and attention with other partnerships that the General Partner and its affiliates do and may sponsor and/or manage;
	●	conflicts caused by the incentive distribution rights which may cause the General Partner to conduct operations that are riskier to the Partnership, or to sell properties, in order to generate distributions from the incentive distribution rights; and
	●	conflicts caused by the management fee the Partnership pays to the General Partner since its compensation is a percentage of total gross equity proceeds raised in the Partnership’s best-efforts offering.

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

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

Additional conflicts of interest may arise between the General Partner and its 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.

2725

Index

●Amounts paid to the General Partner ~~determines the amount and timing of its asset purchases and sales~~, ~~capital~~regardless ~~expenditures and borrowings, each~~ of ~~which~~success ~~can affect the amount~~ of ~~cash that is distributed to holders of~~ the Partnership’s ~~common~~activities, ~~units~~will orreduce ~~used to service its debt obligations; ●~~ the ~~General~~cash ~~Partner controls~~ the ~~enforcement of obligations owed to the~~ Partnership has byavailable ~~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~~distribution.

~~Amounts~~Subsequent to the Partnership’s first acquisition of the Bakken Assets on February 1, 2018, the General Partner and its affiliates began receiving an annual management fee, paid quarterly, which is 0.5% of total gross equity proceeds raised in the Partnership’s offering. After the completion of the Partnership’s best-efforts offering in October 2019, in which approximately $218 million in gross proceeds were raised, the annual management fee to the General Partner is approximately $1.1 million. In addition, ~~regardless~~the ofGeneral ~~success~~Partner and its affiliates have been or will be reimbursed for third-party costs incurred in connection with the formation of the Partnership and the Partnership’s business activities and have been or 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 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 ~~Partnership~~General Partner has ~~available~~sole ~~for~~discretion ~~distribution~~on behalf of the Partnership to select the provider of the services or goods and the provider’s compensation.

~~Subsequent to~~ Because the ~~Partnership’s~~General ~~first~~Partner ~~acquisition~~has ofdiscretion ~~the~~to ~~Bakken~~determine ~~Assets on February 1, 2018,~~ the ~~General~~amount ~~Partner~~ and ~~its~~timing ~~affiliates began receiving an annual management fee, paid quarterly, which is 0.5%~~ of ~~total~~any ~~gross~~distribution ~~equity proceeds raised in~~ the Partnership’s ~~offering.~~may ~~After the completion of the Partnership’s best-efforts offering in October 2019~~make, inthere ~~which approximately $218 million in gross proceeds were raised, the annual management fee to the General Partner~~ is ~~approximately~~no ~~$1.1~~guarantee that ~~million.~~cash Indistributions ~~addition, the General Partner and its affiliates have been or~~ will be ~~reimbursed~~paid ~~for~~by ~~third-party costs incurred in connection with~~ the ~~formation of the~~ Partnership and the Partnership’s business activities and have been or will be reimbursed for general and administrative costs of the general partner allocable to the Partnership regardless of the Partnership’s success in ~~acquiring,~~any ~~developing and operating properties. The fees and direct costs to be paid to the General Partner will reduce the~~ amount ofor ~~cash~~frequency ~~distributions~~even toif ~~investors.~~its ~~With~~operations ~~respect~~generate ~~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~~revenues.

~~Because~~The timing ~~the~~and ~~General~~amount ~~Partner~~of ~~has~~distributions ~~discretion~~will tobe ~~determine~~determined in the ~~amount~~sole ~~and~~discretion ~~timing~~of the General Partner. The level of ~~any~~distributions, ~~distribution~~when made, will primarily be dependent upon the Partnership’s levels of revenue, among other factors. Distributions may ~~make~~be reduced or deferred, ~~there~~in isthe nodiscretion ~~guarantee~~of ~~that~~the ~~cash~~General ~~distributions~~Partner, ~~will~~to bethe ~~paid~~extent bythat the Partnership’s inrevenues ~~any~~are ~~amount~~used or ~~frequency~~reserved ~~even~~for ifany of ~~its~~the ~~operations generate revenues.~~following:

~~The~~● ~~timing~~compensation and ~~amount~~fees ofpaid ~~distributions~~to ~~will~~the beGeneral ~~determined~~Partner and its affiliates as described above in ~~the~~“— ~~sole~~Amounts ~~discretion~~paid ofto the General Partner., ~~The~~regardless ~~level~~of success of ~~distributions,~~the ~~when~~Partnership’s ~~made~~activities, will ~~primarily~~reduce becash ~~dependent~~distributions;” ~~upon~~● ~~the~~repayment ~~Partnership~~of borrowings; ● drilling and completing new wells; ● cost overruns on drilling, completion or operating activities; ● remedial work to improve a well’s ~~levels~~producing capability; ● uninsured losses from operational risks including liability for environmental damages; ● direct costs and general and administrative expenses of ~~revenue~~the Partnership; ● reserves, ~~among~~including ~~other~~a ~~factors.~~reserve ~~Distributions~~for ~~may~~the beestimated ~~reduced~~costs orof ~~deferred,~~eventually inplugging and abandoning the ~~discretion~~wells; or ● indemnification of the General Partner, toand ~~the~~its ~~extent~~affiliates ~~that~~by the Partnership’s ~~revenues~~for ~~are~~losses ~~used~~ or ~~reserved~~liabilities ~~for~~incurred ~~any~~in ofconnection with the ~~following:~~Partnership’s activities.

~~● compensation and fees paid to the General Partner and its affiliates as described above in “— Amounts paid to the General Partner~~Further, because ~~regardless of success of~~ the Partnership’s ~~activities,~~investments will ~~reduce~~be ~~cash~~in ~~distributions;”~~depleting ●assets, ~~repayment~~unless ofreinvested, ~~borrowings;~~Partnership ●revenues ~~drilling~~ and ~~completing~~the ~~new~~amount ~~wells;~~available for ●distribution ~~cost overruns on drilling, completion or operating activities; ● remedial work~~ to ~~improve~~partners awill ~~well’s~~decline ~~producing~~with ~~capability;~~the ●passage ~~uninsured~~of ~~losses~~time. ~~from~~Accordingly, ~~operational~~there ~~risks~~can ~~including~~be ~~liability~~no ~~for~~assurance ~~environmental~~that ~~damages; ● direct costs and general and administrative expenses of~~ the Partnership; ●will be ~~reserves,~~able ~~including~~to amake ~~reserve~~regular ~~for~~distributions ~~the estimated costs of eventually plugging and abandoning the wells;~~ or ●that ~~indemnification~~distributions ofwill ~~the~~be ~~General~~made ~~Partner~~at ~~and~~any ~~its~~consistent ~~affiliates~~rate ~~by the Partnership for losses~~ or ~~liabilities incurred in connection with the Partnership’s activities~~frequency.

~~Further, because the~~ The Partnership’s ~~investments~~may ~~will~~ be inunable ~~depleting~~to ~~assets,~~sell ~~unless~~its ~~reinvested~~properties, ~~Partnership~~merge ~~revenues~~with ~~and~~another ~~the~~entity ~~amount~~or ~~available~~list ~~for distribution to partners will decline with~~ the ~~passage~~common ofunits ~~time.~~on ~~Accordingly,~~a ~~there~~national ~~can~~securities beexchange within noits ~~assurance~~planned ~~that~~timeline ~~the Partnership will be able to make regular distributions~~ or ~~that distributions will be made~~ at ~~any consistent rate or frequency~~all.

The decision to sell the Partnership’s ~~may~~properties or merge with another entity will be ~~unable~~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 natural gas reserves, general economic conditions and other factors that are out of the Partnership’s control. In addition, the ability to ~~sell~~list its ~~properties~~common units on a national securities exchange will depend on a number of factors, ~~merge~~including ~~with~~the ~~another~~amount ~~entity~~of assets, revenues and earnings that the Partnership has at the time of listing, the then existing market for oil and natural gas master limited partnerships, the state of the U.S. securities markets, the Partnership’s ability to meet the 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 ~~within~~in accordance with its ~~planned~~current ~~timeline~~plans, you may be unable to sell or atotherwise transfer your common units and you may lose some or all of your investment. While the Partnership plans to seek a liquidity event within five to seven years, the Partnership Agreement does not obligate the General Partner to cause a liquidity event within that 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 natural gas prices, or other disadvantageous situations.

The General ~~decision~~Partner tomay ~~sell~~cause the Partnership’s ~~properties~~not orto ~~merge~~participate with ~~another entity will be based on a number of factors, including~~ the ~~domestic~~operator ~~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~~drilling of ~~the~~wells 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 its common units on ~~a national securities exchange will depend on a number of factors, including~~ the ~~amount of assets, revenues and earnings that the~~ Partnership ~~has at the time of listing, the then existing market for oil and gas master limited partnerships, the state of the U.S. securities markets, the Partnership~~’s ~~ability to meet the 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, you may be unable to sell or otherwise transfer your common units and you may lose some or all of your investment. While the Partnership plans to seek a liquidity event within five to seven years, the Partnership Agreement does not obligate the General Partner to cause a liquidity event within that 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.

28If 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.

~~Index~~26

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

IfFees ~~the~~and ~~Partnership~~cost ~~has~~reimbursements ~~the~~that ~~opportunity~~must tobe ~~participate~~paid ~~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~~and ~~cause~~ the ~~Partnership~~Dealer toManager ~~“non-consent” the well under the applicable operating agreement. Non-consenting a well~~ will ~~generally~~reduce ~~cause~~ the ~~Partnership~~cash ~~not to be obligated to pay~~ the ~~costs of the well, but the~~ Partnership ~~will~~has ~~not~~available befor ~~entitled to the proceeds of production from the well until a penalty is received by the parties that drilled the well~~distribution. 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~~The General Partner and ~~cost~~its ~~reimbursements~~affiliates ~~that~~have ~~must~~and will receive reimbursement of third-party costs incurred in connection with the formation of the Partnership and the Partnership’s business activities and have and will be ~~paid~~reimbursed tofor general and administrative costs of the General Partner allocable to the Partnership, regardless of the Partnership’s success in acquiring, developing and operating properties. In addition, effective February 1, 2018, the ~~Managing~~General Partner receives an annual management fee of approximately $1.1 million, paid quarterly, which is 0.5% of total gross equity proceeds raised in the Partnership’s best-efforts offering. The Dealer ~~will~~Manager ~~reduce~~is eligible to receive the ~~cash~~Dealer Manager Incentive Fees after Payout. The fees and direct costs to be paid to the ~~Partnership~~General ~~has~~Partner ~~available~~and ~~for~~the ~~distribution~~Dealer Manager will reduce the amount of cash distributions to investors.

~~The~~Risks Related General Partner and its affiliates have and will receive reimbursement of third-party costs incurred in connection with the formation of the Partnership and the Partnership’s business activities and have and will be reimbursed for general and administrative costs of the General Partner allocable to ~~the Partnership~~Laws, ~~regardless of the Partnership’s success in acquiring~~Regulations, ~~developing~~Cybersecurity and ~~operating~~Other ~~properties.~~External In addition, effective February 1, 2018, the General Partner receives an annual management fee of approximately $1.1 million, paid quarterly, which is 0.5% of total gross equity proceeds raised in the Partnership’s best-efforts offering. The Managing Dealer is eligible to receive the Dealer Manager Incentive Fees after Payout. The fees and direct costs to be paid to the General Partner and the Managing Dealer will reduce the amount of cash distributions to investors.Factors

~~Risks~~The Partnership ~~Related~~is subject to ~~Laws~~complex federal, ~~Regulations~~state, ~~Cybersecurity~~local and ~~Other~~other ~~External~~laws ~~Factors~~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 ~~federal~~and stringent laws and regulations governing the acquisition, ~~state~~development, ~~local~~operation, production and ~~other~~marketing of oil and natural 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, ~~that~~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 ~~adversely~~have ~~affect~~a material adverse effect on the ~~cost~~Partnership’s ability to develop its properties, ~~manner~~and receipt of drilling permits with onerous conditions could increase the Partnership’s compliance costs. In addition, regulations or ~~feasibility~~executive orders regarding resource conservation practices and the protection of ~~conducting~~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’s ~~business~~ is subject to ~~complex~~federal, state and ~~stringent~~local laws and regulations ~~governing~~as ~~the~~interpreted ~~acquisition,~~and ~~development,~~enforced ~~operation,~~by ~~production~~governmental ~~and~~authorities ~~marketing~~possessing jurisdiction ofover ~~oil~~various ~~and~~aspects ~~gas,~~of ~~taxation~~the exploration, ~~safety~~production ~~matters~~ and ~~the~~transportation ~~discharge~~ of ~~materials~~oil, ~~into~~natural ~~the~~gas ~~environment.~~and Innatural ~~order~~gas toliquids. ~~conduct~~ While the ~~Partnership’s~~cost ~~operations~~of in compliance with these laws ~~and~~is ~~regulations,~~not ~~the~~expected ~~operator(s)~~to ofbe material to the Partnership’s ~~properties~~operations, ~~must~~the ~~obtain~~possibility ~~and~~exists ~~maintain~~that new ~~numerous permits~~laws, ~~approvals and certificates from various federal~~regulations, ~~state~~executive ~~and~~orders ~~local governmental authorities. Failure~~ or ~~delay~~enforcement inpolicies ~~obtaining and maintaining regulatory approvals or drilling permits~~ could ~~have~~be amore ~~material~~stringent ~~adverse effect on the Partnership’s ability to develop its properties,~~ and ~~receipt~~significantly ~~of drilling permits with onerous conditions could~~ increase the Partnership’s compliance costs. InIf ~~addition,~~the ~~regulations~~Partnership oris ~~executive~~not ~~orders~~able ~~regarding~~to ~~resource~~recover ~~conservation practices and~~ the ~~protection~~resulting ofcosts ~~correlative~~through ~~rights~~insurance ~~may~~or ~~affect~~increased revenues, the Partnership’s ability ~~operations~~to bypay ~~limiting~~distributions ~~the~~to ~~quantity~~holders of ~~oil,~~the ~~natural~~Partnership’s ~~gas~~common units and ~~natural~~service ~~gas liquids~~ the Partnership’s ~~may~~debt ~~produce~~obligations could ~~and~~be ~~sell~~adversely affected.

~~The~~Federal and ~~Partnership is subject to federal,~~ state ~~and~~legislative ~~local~~initiatives ~~laws~~ and ~~regulations~~executive asorders ~~interpreted~~relating ~~and~~to ~~enforced~~hydraulic byfracturing ~~governmental authorities possessing jurisdiction over various aspects of the exploration, production~~ and ~~transportation of~~ oil, ~~natural gas~~ and natural gas ~~liquids.~~lease ~~While~~sales ~~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 beresult in ~~more~~increased ~~stringent~~costs and ~~significantly~~additional ~~increase~~operating ~~the~~restrictions ~~Partnership’s compliance costs. If the Partnership is not able to recover the resulting costs through insurance~~ or ~~increased revenues~~delays, ~~the~~and ~~Partnership’s~~even ~~ability~~could toresult ~~pay~~in ~~distributions to holders of~~ the Partnership’s ~~common~~ceasing ~~units~~business ~~and service the Partnership’s debt obligations could be adversely affected~~operations.

~~Federal~~Hydraulic fracturing ~~and~~is ~~state~~used ~~legislative~~to ~~initiatives~~stimulate production of hydrocarbons, particularly natural gas, from dense rock formations. The hydraulic fracturing process involves the injection of water, sand and ~~executive~~chemicals ~~orders~~under ~~relating~~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 ~~oil~~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 ~~natural~~to ~~gas~~require ~~lease~~disclosure ~~sales~~of ~~could~~the ~~result~~chemicals used in ~~increased~~the ~~costs~~fracturing process; this legislation has not passed. At the state and ~~additional~~local ~~operating~~levels, ~~restrictions~~some orjurisdictions ~~delays~~have adopted, and ~~even~~others are considering adopting, requirements that could ~~result~~impose inmore ~~the~~stringent ~~Partnership~~permitting, ~~ceasing~~public ~~business~~disclosure ~~operations~~of fracturing chemicals or well construction requirements on hydraulic fracturing activities, as well as bans on hydraulic fracturing activities.

~~Hydraulic~~A ~~fracturing~~significant ispercentage ~~used~~of tooil ~~stimulate~~and ~~production~~natural ofgas ~~hydrocarbons~~operations in the United States is conducted on federal lands, ~~particularly~~and the Biden administration took actions to limit future oil and natural gas, ~~from~~operations ~~dense~~on ~~rock~~federal lands ~~formations.~~and ~~The~~to ~~hydraulic~~increase ~~fracturing~~costs ~~process~~of ~~involves~~operations. On January 27, 2021, the ~~injection~~Biden administration signed an executive order directing the Secretary of ~~water,~~the ~~sand~~Interior to temporarily stop issuing new oil and ~~chemicals~~natural ~~under~~gas ~~pressure~~leases ~~into~~on ~~the~~federal ~~formation~~lands, allowing time to ~~fracture~~review and reset the ~~surrounding~~federal government’s ~~rock~~oil and ~~stimulate~~natural ~~production~~gas leasing program. The ~~operators~~Partnership’s ofexisting ~~the~~leases ~~properties~~and ~~the~~permits ~~Partnership~~are ~~owns~~operational ~~will~~and ~~routinely~~held ~~use~~by production, ~~hydraulic~~and ~~fracturing~~were ~~techniques~~therefore innot ~~most~~impacted ~~drilling~~by ~~and~~this ~~completion~~executive ~~programs~~order. InHowever, ~~past~~the ~~legislative~~Biden ~~sessions,~~administration ~~legislation~~proceeded ~~was~~to ~~introduced~~recommend ~~before~~an ~~Congress~~overhaul of the federal oil and natural gas leasing program to ~~provide~~limit areas available for ~~federal~~energy ~~regulation~~development ofand ~~hydraulic~~raise ~~fracturing~~costs ~~using~~for ~~materials~~companies ~~other~~to ~~than~~drill on ~~diesel~~public ~~under~~land. In June 2022, the ~~Safe~~Biden ~~Drinking~~administration ~~Water~~resumed ~~Act~~oil and natural gas lease sales, but limited it to ~~require~~only ~~disclosure~~20% of the ~~chemicals~~total acreage ~~used~~originally innominated ~~the~~for ~~fracturing~~leasing ~~process;~~and ~~this~~increased ~~legislation~~the ~~has~~royalty ~~not passed~~rate. AtIn September 2023, the ~~state~~Biden administration approved three offshore oil and ~~local~~natural ~~levels,~~gas ~~some~~lease ~~jurisdictions~~sales ~~have~~through ~~adopted~~2029, but the sale is limited to the Gulf of Mexico and ~~others~~is ~~are~~the ~~considering~~smallest ~~adopting~~offshore oil drilling plan in the program’s history. In January 2025, ~~requirements~~the ~~that~~Biden ~~could~~administration ~~impose~~withdrew more ~~stringent~~than ~~permitting,~~625 ~~public~~million ~~disclosure~~acres of ~~fracturing~~federal ~~chemicals~~waters from oroffshore ~~well~~drilling, ~~construction~~including ~~requirements~~areas onalong ~~hydraulic~~the ~~fracturing~~Atlantic ~~activities~~Coast, asEastern ~~well~~Gulf asof ~~bans~~Mexico, onand ~~hydraulic~~Pacific ~~fracturing~~Outer ~~activities~~Continental Shelf. Then President-elect Trump announced that he would reverse the withdrawal.

29In 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 on lease sales or prohibitions of hydraulic fracturing could, depending on the makeup of the Partnership’s assets, cause the Partnership to cease business operations.

~~Index~~27

A significant percentage of oil and natural gas operations in the United States is conducted on federal lands, and the Biden administration has taken actions to limit future oil and gas operations on federal lands and to increase costs of operations. 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 were 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 June 2022, the Biden administration resumed oil and natural gas lease sales, but limited it to only 20% of the total acreage originally nominated for leasing and increased the royalty rate. In September 2023, the Biden administration approved three offshore oil and gas lease sales through 2029, but the sale is limited to the Gulf of Mexico and is the smallest offshore oil drilling plan in the program’s history.Index

InAdditional regulatory ~~the~~scrutiny ~~event~~by ~~that~~the ~~new~~EPA orcould ~~more~~make ~~stringent~~it ~~federal,~~difficult ~~state, or local legal restrictions relating~~ to ~~the~~perform hydraulic fracturing, ~~process~~impact ~~are adopted in areas where~~ the Partnership’s ability ~~owns producing properties, the Partnership could incur potentially significant added costs~~ to ~~comply~~conduct ~~with such requirements~~business, ~~experience delays or curtailment in the pursuit of exploration, development, or production activities,~~ and ~~perhaps~~increase ~~even be precluded from participating in drilling wells. More widespread or prolonged moratoriums on lease sales or prohibitions of hydraulic fracturing could, depending on~~ the ~~makeup of the~~ Partnership’s ~~assets,~~costs ~~cause~~of ~~the~~compliance ~~Partnership~~and todoing ~~cease~~ business ~~operations~~.

~~Additional~~Hydraulic ~~regulatory~~fracturing ~~scrutiny~~is typically regulated by state oil and natural gas commissions, but the EPA ~~could~~has ~~make~~asserted itfederal ~~difficult~~regulatory authority pursuant to ~~perform~~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 natural 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 ~~Partnership~~EPA’s assessment. ~~ability~~Although tothe ~~conduct~~second ~~business~~Trump administration has voiced support for deregulation on environmental matters, 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 ~~costs~~operations or result in additional operating restrictions or delays. Restrictions on hydraulic fracturing could reduce the amount of ~~compliance~~oil and ~~doing~~natural ~~business~~gas that the Partnership ultimately is able to produce.

~~Hydraulic~~The Partnership’s ~~fracturing~~financial iscondition ~~typically regulated by state oil~~ and ~~natural~~results ~~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.~~operations ~~The~~may ~~EPA~~be ~~has~~materially ~~announced~~adversely anaffected ~~initiative~~if ~~under~~ the ~~Toxic~~Partnership incurs ~~Substance~~costs ~~Control Act to develop regulations governing the disclosure~~ and ~~evaluation~~liabilities ofdue ~~hydraulic~~to ~~fracturing chemicals. The EPA also issued~~ a ~~pretreatment~~failure ~~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~~comply ~~owned~~with 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~~regulations ~~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~~a inrelease ~~additional operating restrictions or delays. Restrictions on hydraulic fracturing could reduce the amount~~ of ~~oil~~hazardous ~~and~~substances ~~natural~~into ~~gas that~~ the ~~Partnership ultimately is able to produce~~ environment.

The Partnership’s ~~financial~~may ~~condition~~incur significant costs and ~~results~~liabilities ofas ~~operations~~a ~~may~~result beof ~~materially~~environmental ~~adversely~~requirements ~~affected~~applicable ifto the ~~Partnership~~operation ~~incurs~~of ~~costs~~its wells, ~~and~~gathering ~~liabilities~~systems ~~due~~and toother afacilities. ~~failure~~These tocosts ~~comply~~and ~~with~~liabilities ~~environmental~~could ~~regulations~~arise orunder a ~~release~~wide range of ~~hazardous~~federal, ~~substances~~state ~~into~~and ~~the~~local environmental ~~environment.~~laws and regulations, including, for example:

~~The~~● ~~Partnership~~the ~~may~~Clean ~~incur~~Air ~~significant~~Act, ~~costs~~or the CAA, and ~~liabilities~~comparable asstate alaws ~~result~~and ofregulations ~~environmental~~that ~~requirements~~impose ~~applicable~~obligations related to emissions of air pollutants; ● the ~~operation~~Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of ~~its~~pollutants ~~wells,~~into ~~gathering~~regulated ~~systems~~waters; ● the Resource Conservation and ~~other~~Recovery ~~facilities.~~Act, ~~These~~or ~~costs~~RCRA, and ~~liabilities~~comparable ~~could~~state ~~arise~~laws ~~under~~that aimpose ~~wide~~requirements ~~range~~for the handling and disposal of ~~federal~~waste from oil and natural gas 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 by the Partnership or at locations to which the Partnership has sent waste for disposal; ● the Safe Drinking Water Act and state or local ~~environmental~~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; ● 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 subjects responsible parties to liability for ~~example:~~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 the Partnership’s operations.

●Under these ~~the Clean Air Act, or the CAA, and comparable state~~ laws and regulations, ~~that~~the ~~impose~~Partnership ~~obligations~~could ~~related~~be toliable ~~emissions~~for costs of ~~air~~investigation, ~~pollutants;~~removal ~~● the Clean Water Act~~ and ~~comparable~~remediation, ~~state~~damages ~~laws~~to and ~~regulations~~loss of ~~that~~use ~~impose~~of ~~obligations~~natural ~~related~~resources, toloss ~~discharges~~ of ~~pollutants~~profits ~~into~~or ~~regulated~~impairment ~~waters;~~of ●earning ~~the Resource Conservation and Recovery Act~~capacity, orproperty ~~RCRA~~damages, ~~and~~costs ~~comparable~~of ~~state~~increased ~~laws~~public ~~that~~services, as ~~impose~~well ~~requirements~~as ~~for~~administrative, ~~the~~civil ~~handling~~ and ~~disposal~~criminal offines ~~waste~~and ~~from~~penalties ~~oil~~ and ~~gas facilities; ●~~ the ~~Comprehensive~~issuance ~~Environmental~~of ~~Response,~~orders ~~Compensation,~~enjoining ~~and~~future ~~Liability~~operations. ~~Act~~Certain environmental statutes, orincluding CERCLA, OPA and ~~comparable~~analogous state laws ~~that~~and ~~regulate~~regulations, ~~the~~impose ~~cleanup~~strict ofjoint ~~hazardous~~and ~~substances~~several ~~that~~liability ~~may~~for ~~have~~costs ~~been~~required to ~~released~~clean atup ~~properties~~and ~~currently~~restore orsites ~~previously~~where ~~owned~~hazardous bysubstances ~~the Partnership~~ or atother ~~locations to which the Partnership has sent~~ waste ~~for~~products ~~disposal;~~have ●been ~~the~~disposed ~~Safe~~of ~~Drinking~~or ~~Water~~otherwise ~~Act~~released. ~~and~~More ~~state or local~~ stringent laws and regulations, ~~related to underground injection (~~including ~~hydraulic~~any ~~fracturing);~~related ●to ~~the~~climate ~~Endangered~~change ~~Species Act~~ and ~~comparable~~greenhouse ~~state~~gases, ~~and~~may ~~local~~be ~~laws~~adopted and regulations which protect endangered and threatened species and the ecosystems on which they depend; ● 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~~future. ~~of government land); ● the Oil Pollution Act~~Moreover, orit ~~OPA,~~is ~~which~~not uncommon ~~subjects responsible parties to liability~~ for ~~removal~~neighboring ~~costs~~landowners and ~~damages~~other ~~arising~~third ~~from~~parties anto ~~oil~~file ~~spill~~claims infor ~~waters~~personal ofinjury ~~the U.S.;~~ and ●property ~~emergency~~damage ~~planning~~allegedly ~~and~~caused ~~community right to know regulations under~~ by the ~~Title~~release ~~III~~ of ~~CERCLA~~hazardous ~~and~~substances ~~similar state statutes require that the Partnership organizes and/~~or ~~discloses~~other ~~information~~waste ~~about~~products ~~hazardous~~into ~~materials used or produced in~~ the ~~Partnership’s operations~~environment.

30Climate 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.

~~Index~~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 issued rules to significantly reduce methane emissions from new and existing oil and natural gas production sources and natural gas processing and transmission sources. The broader recent trend of more expansive and stricter climate change regulation could stall at the federal level in a second Trump administration, but the long-term trend of more expansive and stricter regulation, including at the state level, may continue for the long term.

Under these laws and regulations, the Partnership could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties 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.28

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.Index

In addition, the ~~absence~~EPA requires the reporting of ~~comprehensive~~GHG ~~federal~~emissions ~~legislation~~from onspecified large GHG emission ~~control,~~sources ~~the~~including ~~EPA~~onshore ~~attempted~~and tooffshore ~~require~~oil and ~~the~~natural ~~permitting~~gas ofproduction ~~GHG~~facilities ~~emissions.~~and ~~Although~~onshore ~~the~~oil ~~Supreme~~and ~~Court~~natural ~~struck~~gas ~~down~~processing, ~~the~~transmission, ~~permitting~~storage ~~requirements~~and distribution facilities, which itmay ~~upheld~~include facilities the ~~EPA’s~~Partnership ~~authority~~owns. toReporting ~~control~~of GHG emissions ~~when~~from asuch ~~permit~~facilities is required ~~due~~on toan ~~emissions~~annual ~~of other pollutants~~basis. ~~These permitting provisions, to~~ Should the ~~extent applicable to the Partnership’s operations, could require the~~ operator(s) of the Partnership’s properties totrigger ~~implement~~the ~~emission~~reporting ~~controls~~requirement, ~~or other measures to reduce GHG emissions and~~ the Partnership ~~could~~will incur ~~additional~~ costs to satisfy those requirements. Further, the EPA has issued rules to significantly reduce methane emissions from new and existing oil and natural gas production sources and natural gas processing and transmission sources. The broader recent trend of more expansive and stricter climate change regulation may continue for the long term, including associated with the ~~Biden~~reporting ~~administration’s return to the Paris Agreement global treaty to curb greenhouse gas emissions~~obligation.

In past ~~addition~~legislative sessions, ~~the~~Congress ~~EPA~~considered ~~requires~~comprehensive ~~the~~federal ~~reporting~~legislation to reduce emissions of GHGs and many states and regions meanwhile have adopted or have considered measures to reduce GHG ~~emissions~~emission ~~from~~reduction ~~specified~~levels, ~~large~~often involving the planned development of GHG emission ~~sources~~inventories ~~including~~and/or ~~onshore~~cap and ~~offshore~~trade ~~oil~~programs. Most of these cap and ~~natural~~trade ~~gas~~programs ~~production~~work ~~facilities~~by ~~and~~requiring ~~onshore~~major ~~oil~~sources ~~and~~of ~~natural~~emissions or ~~gas~~major ~~processing,~~producers ~~transmission,~~of ~~storage~~fuels to acquire and ~~distribution~~surrender ~~facilities,~~emission ~~which~~allowances. ~~may~~Federal ~~include~~efforts ~~facilities~~at ~~the~~a ~~Partnership~~cap ~~owns~~and trade program have not moved forward in Congress. ~~Reporting~~The adoption and implementation of ~~GHG~~any ~~emissions~~legislation ~~from~~or ~~such~~regulatory ~~facilities~~programs isimposing ~~required~~reporting obligations on, anor ~~annual~~limiting emissions ~~basis.~~of ~~Should~~GHGs ~~the~~from, ~~operator(s)~~equipment ofand operations on the Partnership’s properties ~~trigger~~could ~~the~~require ~~reporting requirement,~~ the Partnership ~~will~~to incur costs to reduce emissions of GHGs associated with the ~~reporting~~Partnership’s ~~obligation~~operations or could adversely affect demand for the oil, natural gas and natural gas liquids that the Partnership produces.

InSignificant physical ~~past~~effects ~~legislative sessions, Congress considered comprehensive federal legislation to reduce emissions~~ of ~~GHGs~~climatic ~~and~~change ~~many states and regions meanwhile~~ have ~~adopted~~the orpotential ~~have considered measures~~ to ~~reduce~~damage ~~GHG emission reduction levels, often involving~~ the ~~planned~~Partnership’s 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. The adoption and implementation of any legislation or regulatory programs imposing reporting obligations onfacilities, ordisrupt ~~limiting emissions of GHGs from, equipment and operations on~~ the Partnership’s production ~~properties~~activities ~~could~~and ~~require~~cause the Partnership to incur significant costs toin ~~reduce~~preparing ~~emissions~~for ~~of GHGs associated with the Partnership’s operations~~ or ~~could~~responding ~~adversely~~to ~~affect~~those ~~demand for the oil, natural gas and natural gas liquids that the Partnership produces~~effects.

~~Significant~~In an ~~physical~~interpretative ~~effects~~guidance ofon ~~climatic~~climate change disclosures, the SEC indicated that climate change could have an effect on the ~~potential~~severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to ~~damage~~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, ~~disrupt~~disruption of the Partnership’s production activities ~~and~~either ~~cause~~because of climate-related damages to the Partnership’s tofacilities ~~incur~~or ~~significant~~the Partnership’s costs of inoperation ~~preparing~~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 ~~responding~~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 ~~those~~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.

InCyber-attacks antargeting ~~interpretative~~systems ~~guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes~~ and ~~floods),~~infrastructure used ~~sea~~by ~~levels,~~ the ~~arability~~oil ~~of farmland,~~ and ~~water~~natural ~~availability~~gas ~~and~~industry ~~quality. If such effects were to occur, the operations that the Partnership plans to engage in~~ may be adversely ~~affected.~~impact ~~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.

31The 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 natural 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 natural 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:

~~Index~~● 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 natural 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.

~~Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact the Partnership’s operations.~~29

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:Index

●All of ~~Unauthorized~~the ~~access~~above ~~to seismic data, reserves information, strategic information, or other sensitive or proprietary information~~ could ~~have~~negatively ~~a negative~~ impact on the Partnership’s ~~ability~~operational ~~to compete for oil~~ and ~~gas~~financial ~~resources;~~results. ~~● Data corruption~~Additionally, ~~communication~~certain 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~~incidents, such ~~pipeline,~~as ~~or rail transportation systems could delay or prevent the Partnership from transporting and marketing its production~~surveillance, ~~resulting~~may inremain aundetected ~~loss~~for ofan ~~revenues;~~extended ●period. AAs cyber~~-attack~~ ~~involving~~threats ~~commodities~~continue ~~exchanges~~to ~~or financial institutions could slow or halt commodities trading~~evolve, ~~thus preventing~~ the Partnership ~~from~~may ~~marketing~~be ~~its~~required to ~~production~~expend ~~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~~additional onresources ~~the~~to ~~natural~~continue ~~gas~~to ~~market,~~modify ~~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~~enhance ~~grid~~its ~~could~~protective ~~cause~~measures 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~~investigate ~~fines or penalties;~~ and ●remediate Aany information ~~cyber-attack~~security ~~resulting~~vulnerabilities. ~~in the loss or disclosure of~~Additionally, ~~or damage to,~~ the ~~Partnership’s~~growth ~~or any~~ of ~~its~~cyber-attacks ~~customer’s~~has orresulted ~~supplier’s~~in ~~data~~evolving ~~or confidential information could harm the Partnership’s business by damaging its reputation, subjecting it to potential financial or~~ legal ~~liability,~~ and ~~requiring~~compliance itmatters which toimpose ~~incur~~ significant costs, ~~including~~that ~~costs~~are tolikely ~~repair or restore its systems and data or~~ to ~~take~~increase ~~other~~over ~~remedial steps~~time.

~~All~~ Loss of ~~the above could negatively impact the~~ Partnership’s ~~operational~~information and ~~financial~~computer ~~results.~~systems ~~Additionally,~~could ~~certain~~adversely ~~cyber~~affect ~~incidents, such as surveillance, may remain undetected for an extended period. As cyber threats continue to evolve,~~ the Partnership’s ~~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~~business. ~~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~~The Partnership ofwill ~~Partnership~~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 ~~adversely~~have ~~affect~~a material adverse effect on the Partnership’s business.

~~The~~Tax Risks 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~~Limited 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.Partners

~~Tax~~The Partnership’s ~~Risks~~tax treatment depends on its status as a partnership for U.S. federal income tax purposes and not being subject to ~~Limited~~a ~~Partners~~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 ~~Partnership’s~~ after-tax ~~treatment~~economic benefit of an investment in the common units depends largely on ~~its~~the ~~status~~Partnership being treated as a partnership for U.S. federal income tax purposes. ~~and~~Despite ~~not~~ being ~~subject~~organized toas a ~~material~~partnership ~~amount~~under ofstate ~~entity-level~~law, ~~taxation~~the byPartnership ~~individual~~will ~~states~~be treated as a corporation for U.S. Iffederal ~~the~~income ~~Internal~~tax ~~Revenue~~purposes ~~Service~~unless ~~treats~~it satisfies the ~~Partnership~~“qualifying asincome” arequirement. ~~corporation~~Based oron the Partnership’s current ~~becomes~~operations, ~~subject~~the toPartnership abelieves ~~material~~it ~~amount~~satisfies ofthe ~~entity-level~~qualifying ~~taxation~~income ~~for~~requirement. ~~state~~The ~~tax~~Partnership ~~purposes~~has not requested, itand ~~would~~does not ~~reduce~~plan to request, a ruling from the ~~amount~~Internal ofRevenue ~~cash~~Service ~~available~~(“IRS”) ~~for~~on ~~distribution~~this toor ~~the~~any ~~Partnership’s~~other ~~limited~~tax ~~partners~~matter affecting it.

~~The~~If the ~~anticipated~~Partnership ~~after-tax~~was ~~economic~~treated ~~benefit~~as ofa ancorporation ~~investment~~for inU.S. federal income tax purposes, the ~~common~~Partnership ~~units~~would ~~depends~~pay ~~largely~~federal income tax on the Partnership’s ~~being~~taxable ~~treated~~income asat the corporate tax rate, which, effective January 1, 2018, is currently a ~~partnership~~maximum ~~for~~of ~~U.S.~~21% ~~federal~~and likely would pay state income tax ~~purposes~~at varying rates. ~~Despite~~Distributions ~~being~~to ~~organized~~a limited partner would generally be taxed again as acorporate ~~partnership~~distributions, and ~~under~~no ~~state~~income, ~~law~~gains, ~~the~~losses ~~Partnership~~or ~~will~~deductions bewould ~~treated~~flow asthrough to a ~~corporation~~limited ~~for U~~partner.S. ~~federal~~Because ~~income~~a tax ~~purposes~~would ~~unless~~be itimposed ~~satisfies~~upon the ~~“qualifying~~Partnership as ~~income”~~a ~~requirement.~~corporation, ~~Based~~cash onavailable ~~the~~for ~~Partnership’s~~distribution ~~current~~to ~~operations,~~a ~~the~~limited ~~Partnership~~partner ~~believes~~would itbe ~~satisfies~~substantially ~~the~~reduced. ~~qualifying~~Therefore, ~~income~~treatment ~~requirement.~~of ~~The~~the Partnership as ~~has~~a ~~not~~corporation ~~requested,~~would ~~and~~result ~~does~~in ~~not~~a ~~plan~~material toreduction ~~request,~~in athe ~~ruling~~anticipated ~~from~~cash flows and after-tax return to the ~~Internal~~limited ~~Revenue~~partners, ~~Service~~likely causing ~~(“IRS”)~~a onsubstantial ~~this~~reduction orin ~~any~~the ~~other~~value ~~tax~~of ~~matter~~the ~~affecting~~Partnership’s itcommon units.

32Current 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.

~~Index~~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.

IfThe Partnership has not requested a ruling from the ~~Partnership~~IRS ~~was~~with ~~treated~~respect to its treatment as a ~~corporation~~partnership for U.S. federal income tax purposes, or ~~the~~any ~~Partnership~~other ~~would~~matter ~~pay~~affecting ~~federal income tax on~~ the Partnership’s. ~~taxable~~It ~~income~~may atbe ~~the~~necessary ~~corporate~~to ~~tax~~resort ~~rate,~~to ~~which,~~administrative ~~effective~~or ~~January~~court 1,proceedings ~~2018,~~to issustain ~~currently~~some aor all ~~maximum~~ of ~~21%~~the ~~and~~Partnership’s ~~likely~~counsel’s ~~would~~conclusions ~~pay~~or ~~state~~the ~~income~~positions ~~tax~~the atPartnership ~~varying rates~~takes. ~~Distributions~~A tocourt amay ~~limited~~not ~~partner~~agree ~~would~~with ~~generally~~all beof the ~~taxed~~Partnership’s ~~again~~counsel’s asconclusions ~~corporate~~or ~~distributions,~~positions ~~and~~the noPartnership ~~income,~~takes. ~~gains,~~Any ~~losses~~contest orwith ~~deductions~~the ~~would~~IRS ~~flow~~may ~~through~~materially toand aadversely impact ~~limited~~the ~~partner.~~value ~~Because~~of athe ~~tax~~Partnership’s ~~would~~units. beIn ~~imposed~~addition, ~~upon~~costs ~~the~~incurred ~~Partnership~~in asany acontest ~~corporation,~~with ~~cash~~the ~~available~~IRS ~~for~~will ~~distribution~~be toborne aindirectly by limited ~~partner~~partners ~~would~~and bethe ~~substantially~~General ~~reduced.~~Partner ~~Therefore,~~because ~~treatment~~the ofcosts will reduce the Partnership’s ascash aavailable ~~corporation~~for ~~would~~distribution. ~~result~~In in addition, a ~~material~~successful ~~reduction~~IRS inchallenge to the ~~anticipated~~Partnership’s ~~cash~~U.S. ~~flows~~federal ~~and~~income ~~after-~~tax ~~return~~positions tocould ~~the~~adversely ~~limited~~affect ~~partners~~the amount, ~~likely~~character and ~~causing~~timing aof ~~substantial~~taxable ~~reduction~~income inor ~~the~~loss ~~value~~allocated ofto ~~the~~limited ~~Partnership’s common units~~partners.

~~Current~~If the ~~law~~IRS ~~may~~makes ~~change~~audit soadjustments as to ~~cause~~ the Partnership’s ~~to be treated as a corporation for U.S. federal~~ income tax ~~purposes or otherwise subject the Partnership to entity-level taxation. In addition~~returns, ~~because~~it ~~of widespread state budget deficits~~ (and ~~other~~some ~~reasons, several~~ states) ~~have~~may ~~ways~~assess toand ~~subject~~collect any ~~partnerships~~taxes to(including ~~entity-level~~any ~~taxation~~applicable ~~through~~penalties ~~the imposition of state income, franchise~~ and ~~other~~interest) ~~forms~~resulting offrom ~~taxation.~~such ~~Imposition~~audit ofadjustment ~~such~~directly ~~taxes~~from on the Partnership, ~~will~~in ~~reduce~~which case ~~the~~ cash available for distribution to a limited ~~partner~~partners might be substantially reduced.

AnIf the IRS ~~contest~~makes ofaudit adjustments to the Partnership’s Uincome 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.S. ~~federal~~To ~~income~~the ~~tax~~extent ~~positions~~possible under these rules, the General Partner may ~~adversely~~elect ~~affect~~to either pay the ~~value~~taxes ~~for~~(including any applicable penalties and interest) directly to the IRS or, if the Partnership’s ~~common~~is ~~units~~eligible, issue a revised Schedule K-1 to each limited partner with respect to an audited and adjusted return. Although the ~~cost~~General ofPartner ~~any~~may ~~IRS~~elect ~~contest~~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 ~~reduce~~be practical, permissible or effective in all circumstances. As a result, the Partnership’s ~~cash~~current ~~available~~limited ~~for~~partners ~~distribution~~may tobear some or all of the ~~Partnership’~~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.

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.30

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 KTax-1exempt entities ~~to each limited partner with respect to an audited~~ and ~~adjusted~~foreign ~~return.~~persons ~~Although~~face ~~the~~unique ~~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~~issues ~~under~~from ~~audit,~~owning ~~there~~common ~~can~~units ~~be no assurance~~ that ~~such~~may ~~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~~adverse ~~Partnership during the~~ tax ~~year~~consequences ~~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.them

~~Tax~~Investment in Partnership common units by tax-exempt entities, such as individual retirement accounts (“IRAs”), and ~~foreign~~non-U.S. persons raises ~~face~~issues unique ~~tax~~to ~~issues~~them. For example, much of the Partnership’s income allocated to organizations that are exempt from ~~owning~~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. Cash distributions on Partnership common units paid to foreign persons will be reduced by withholding taxes at the highest applicable effective U.S. tax rate, and foreign persons that hold Partnership common units will be required to file U.S. federal tax returns and pay tax on their share of our taxable income allocated to them. Upon the sale, exchange or other disposition of a common unit by a foreign person, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. Beginning in 2023, the IRS has clarified that brokers generally are responsible for withholding 10% of the gross proceeds upon sale of an investment in a publicly traded partnership by a foreign investor. Distributions to foreign persons may ~~result~~also be subject to additional withholding of 10% under these rules to the extent a portion of a distribution is attributable to an amount in ~~adverse~~excess of Partnership cumulative net income that has not previously been distributed. Non-U.S. and tax-exempt ~~consequences~~limited partners should consult their tax advisors regarding the tax implications to them of on an investment in the Partnership’s common units.

~~Investment~~A limited inpartner ~~Partnership~~may 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~~taxes on ~~their share of the Partnership’s taxable~~ income. ~~Cash~~from ~~distributions on Partnership common units paid to foreign persons will be reduced by withholding taxes at~~ the ~~highest applicable effective U.S. tax rate, and foreign persons that hold~~ Partnership ~~common~~even units will be required to file U.S. federal tax returns and pay tax on their share of our taxable income allocated to them. Upon the sale, exchange or other disposition of a common unit by a foreign person, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if ~~any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with~~ a ~~U.S.~~limited ~~trade~~partner ordid business. Beginning in 2023, the IRS has clarified that brokers generally are responsible for withholding 10% of the gross proceeds upon sale of an investment in a publicly traded partnership by a foreign investor. Distributions to foreign persons may also be subject to additional withholding of 10% under these rules to the extent a portion of a distribution is attributable to an amount in excess of Partnership cumulative net income that has not ~~previously~~receive ~~been~~any ~~distributed.~~cash ~~Non-U.S.~~distributions from ~~and tax-exempt limited partners should consult their tax advisors regarding~~ the ~~tax implications to them of on an investment in the~~ Partnership~~’s common units~~.

33Because 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.

~~Index~~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.

APercentage depletion ~~limited partner~~ may be ~~required~~available with respect to ~~pay~~limited ~~taxes~~partners onwho ~~income~~qualify ~~from~~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 ~~even~~cannot determine whether, or provide any assurance, that a limited partner will qualify as an independent producer. Further, if a limited partner ~~did~~does qualify ~~not~~as ~~receive~~an ~~any~~independent ~~cash~~producer, ~~distributions~~the ~~from~~limited partner is required to determine the ~~Partnership~~amount of the allowed percentage depletion deduction and maintain records supporting such determination.

~~Because holders of the~~ The Partnership’s ~~common~~cannot ~~units~~assure ~~will~~its belimited ~~treated as~~ partners tothat ~~whom~~it ~~the Partnership~~ will ~~allocate~~meet ~~taxable income which could be different in amount than~~ the ~~cash~~requirements ~~the~~for ~~Partnership~~its ~~distributes, a~~ limited ~~partner~~partners ~~will be required~~ to ~~pay~~deduct ~~any~~intangible ~~federal income taxes~~ drilling and, indevelopment ~~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~~costs. ~~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.~~

AFederal ~~limited~~tax ~~partner~~law ~~may~~places ~~not~~substantial ~~qualify~~limits ~~for~~on ~~percentage~~taxpayers’ ability ~~depletion~~to ~~deductions~~deduct intangible drilling and development costs (“IDCs”). Generally speaking, an “operator” is permitted to elect to currently deduct or capitalize and ~~even~~deduct ifratably over a ~~limited~~60-month ~~partner~~period, ~~does~~costs sothat ~~qualify~~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 ~~limited~~working ~~partner~~or ~~will~~an beoperating ~~required~~interest in an oil or gas well. If the Partnership determines that it is an “operator” with respect to ~~determine~~its oil and natural 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, ~~maintain~~therefore, ~~records~~its ~~supporting~~limited partners, would not be entitled to deduct the ~~deduction~~IDCs incurred in connection with such wells.

Percentage depletion may be 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.31

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

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 aneligible ~~“operator” with respect~~ to ~~its~~deduct 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,~~cannot ~~therefore,~~assure its limited partners, ~~would~~that ~~not~~IDCs will be ~~entitled~~deductible ~~to deduct the IDCs incurred~~ in ~~connection~~any ~~with such wells~~given year.

If the Partnership is ~~eligible~~deemed to ~~deduct~~be ~~IDCs~~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 ~~cannot~~as ~~assure~~an ~~its~~IDC ~~limited~~as ~~partners~~a cost that ~~IDCs~~must ~~will~~ be ~~deductible~~capitalized or inthat ~~any~~is ~~given~~not ~~year~~deductible.

~~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~~could ~~reclassify~~challenge anthe ~~item~~timing ~~classified~~of by the Partnership’s asdeductions anof ~~IDC~~IDCs, aswhich acould ~~cost~~result ~~that~~in ~~must~~an beincrease ~~capitalized~~to orlimited partners’ ~~that~~tax ~~is not deductible~~liabilities.

~~The~~IDCs are ~~IRS~~generally ~~could~~deductible ~~challenge~~when the ~~timing~~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 ~~deductions~~may ofnot be drilled during the year when the Partnership pays IDCs pursuant to a drilling contract. As a result, ~~which~~the Partnership could ~~result~~fail into ansatisfy ~~increase~~the requirements to ~~limited~~deduct ~~partners~~the IDCs in the year when paid and/or the IRS may challenge the timing of the Partnership’s deduction ~~tax~~of ~~liabilities~~prepaid IDCs.

~~IDCs~~The ability 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~~limited ~~contract.~~partner ~~As a result, the Partnership could fail~~ to ~~satisfy the requirements to~~ deduct ~~the~~its ~~IDCs~~share inof ~~the~~our ~~year~~losses ~~when paid~~ and~~/or~~ ~~the~~deductions ~~IRS~~ may ~~challenge~~be ~~the timing of the Partnership’s deduction of prepaid IDCs~~limited.

~~The~~Various limitations may apply to the ability of a ~~limited~~holder ~~partner~~of the Partnership’s common units to deduct its share of ~~our~~its losses and deductions, including the limited partner’s share of the Partnership’s deduction for IDCs. For example, in the case of taxpayers subject to the passive activity loss rules (generally, individuals and closely held corporations), any losses and deductions generated by the Partnership will only be available to offset its future income and cannot be used to offset income from other activities, including other passive activities or investments. Such unused losses and deductions may be ~~limited~~deducted when the taxpayer disposes of its entire investment in the Partnership in a fully taxable transaction with an unrelated party, such as a sale of all of its common units in the open market. A unit holder’s share of any net passive income may be offset by unused losses from the Partnership carried over from prior years, but not by losses from other passive activities.

~~Various~~Certain federal ~~limitations~~income ~~may~~tax ~~apply to the ability of a holder of the Partnership’s common units to deduct its share of its losses and~~ deductions, ~~including~~currently ~~the~~available ~~limited~~with ~~partner’s~~respect ~~share of the Partnership’s deduction for IDCs. For example, in the case of taxpayers subject~~ to ~~the~~oil ~~passive activity loss rules (generally, individuals~~ and ~~closely~~natural ~~held~~gas ~~corporations),~~exploration ~~any losses~~ and ~~deductions~~development generated by the Partnership will only be available to offset its future income and cannot be used to offset income from other activities, including other passive activities or investments. Such unused losses and deductions may be ~~deducted~~eliminated ~~when the taxpayer disposes of its entire investment in the Partnership in a fully taxable transaction with an unrelated party, such~~ as a ~~sale~~result of ~~all~~future ~~of its common units in the open market~~legislation. ~~A unit holder’s share of any net passive income may be offset by unused losses from the Partnership carried over from prior years, but not by losses from other passive activities.~~

34The U.S. legislature regularly considers budget proposals that may impact many tax incentives and deductions that are currently used by U.S. oil and natural 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 natural gas companies; and an increase in the amortization period for geological and geophysical costs of independent producers.

~~Index~~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.

~~Certain~~Limited partners ~~federal~~may ~~income~~be ~~tax~~subject ~~deductions currently available with respect~~ to ~~oil~~a ~~and~~limit ~~natural~~on ~~gas~~the ~~exploration~~ability ~~and~~to ~~development~~deduct ~~may~~interest beexpense ~~eliminated~~incurred asby athe ~~result of future legislation~~Partnership.

~~The~~In general, ~~U.S.~~holders ~~legislature~~of ~~regularly~~the ~~considers~~Partnership’s ~~budget~~common ~~proposals~~units ~~that~~are ~~may~~entitled ~~impact~~to ~~many~~a ~~tax~~deduction ~~incentives~~for ~~and~~interest ~~deductions~~paid ~~that~~or ~~are~~accrued ~~currently~~on ~~used~~indebtedness byproperly allocable ~~U.S.~~to ~~oil~~the ~~and~~Partnership’s ~~gas~~trade ~~companies~~or business during its taxable year. ~~Among~~However, ~~others~~for taxable years beginning after December 31, 2017, ~~budget~~the ~~provisions~~deduction ~~may~~for ~~include:~~“business ~~repeal~~interest” is limited to the sum of the ~~deduction~~Partnership’s business interest income and 30% of ~~IDC;~~“adjusted ~~repeal~~taxable income.” For the purposes of this limitation, the ~~percentage~~Partnership’s ~~depletion~~adjusted ~~deduction~~taxable ~~for~~income ~~oil~~is computed ~~and~~without ~~natural~~regard ~~gas~~to ~~properties;~~any ~~repeal~~business ofinterest expense or business interest income, and in the ~~domestic~~case ~~manufacturing~~of ~~tax~~taxable years beginning before January 1, 2022, any deduction allowable for ~~oil~~depreciation, ~~and~~amortization, ~~gas~~or ~~companies;~~depletion. ~~and~~Any andisallowed ~~increase~~business interest expense is then generally carried forward as a deduction in a succeeding taxable year at the ~~amortization~~partner ~~period~~level. ~~for~~These ~~geological~~limitations ~~and~~might ~~geophysical~~cause ~~costs~~interest ofexpense to ~~independent~~be ~~producers~~deducted by Partnership unit holders in a later period than recognized in the GAAP financial statements.

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 A limited partner. ~~The Partnership is unable to predict whether any of these changes, or other proposals,~~ will ~~ultimately~~likely be ~~enacted.~~subject ~~Any~~to ~~modifications~~state toand ~~the~~local ~~federal~~taxes ~~income~~and tax ~~laws~~return orfiling ~~interpretations~~requirements ~~thereof~~in ~~may~~states orwhere ~~may~~they do not belive ~~applied~~as a ~~retroactively.~~result ~~Any such changes could negatively impact the value~~ of aninvesting ~~investment~~ in the Partnership’s common units.

~~Limited~~In addition ~~partners~~to ~~may~~federal income taxes, a limited partner will likely be subject to aother ~~limit~~taxes, onincluding ~~the~~state ~~ability~~and tolocal ~~deduct~~taxes, ~~interest~~unincorporated business ~~expense~~taxes ~~incurred~~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.

In general, holders of the Partnership’s common units are 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 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. Any disallowed business interest expense is then generally carried forward as a deduction in a succeeding taxable year at the partner level. These limitations might cause interest expense to be deducted by Partnership unit holders in a later period than recognized in the GAAP financial statements.32

~~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~~Index

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 The Partnership ~~does~~may ~~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~~remit ~~state~~federal ~~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~~applicable ~~for~~taxing ~~failure~~authorities toon ~~comply~~behalf ~~with those requirements. It is the responsibility~~ of ~~each~~its limited ~~partner to file its own federal, state and local tax returns, as applicable~~partners.

~~The~~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 benot ~~required~~qualify tofor ~~remit~~these ~~federal~~exceptions ~~income~~based ~~taxes~~upon the precise legal definitions involved. If the Partnership is required to ~~applicable~~remit ~~taxing~~income ~~authorities~~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.

~~Many~~In mid-2022, ~~states~~the ~~require~~Partnership was contacted by the state of North Dakota, which asserted that ~~partnerships~~the Partnership has an obligation to make tax payments on behalf of certain non-resident partners. ~~who~~In ~~are~~accordance ~~non-residents~~with ofits settlements with the state of North Dakota, the Partnership has made payments of (i) approximately $365,000 (approximately $0.033 ~~Although~~per ~~many~~common ~~states~~unit) ~~have~~in ~~exceptions~~May 2023 for ~~publicly~~tax ~~traded~~year ~~partnerships~~2021; (ii) approximately $532,000 ~~the~~(approximately ~~Partnership~~$0.048 ~~may~~per ~~not~~common ~~qualify~~unit) in April 2024 for ~~these~~tax ~~exceptions~~year ~~based~~2022; ~~upon~~and ~~the~~(iii) ~~precise~~approximately ~~legal~~$142,000 ~~definitions~~(approximately ~~involved~~$0.013 per Ifcommon ~~the~~unit) ~~Partnership~~in isApril ~~required~~2024 tofor ~~remit~~tax ~~income~~year ~~tax~~2023. onThe ~~behalf~~Partnership ofrecorded ~~its~~an ~~limited~~estimate ~~partners~~at December 31, 2024 of approximately $135,000 for the ~~Partnership~~2024 ~~Agreement~~tax ~~permits~~year. ~~such~~If ~~withholdings~~a topayment beof ~~treated~~taxes asis amade ~~distribution~~on tobehalf of limited partners, the affected partners, ~~since~~should ~~the~~be able to claim the amounts remitted ~~represent~~as a tax payment ofon their originally filed or amended income tax onreturns ~~behalf~~to the state of ~~the~~North ~~affected~~Dakota, ~~partners~~as appropriate.

~~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~~Item 1B. ~~The~~Unresolved ~~Partnership~~Staff reached a resolution with the state of North Dakota that entailed the Partnership making a payment of taxes on behalf of certain non-resident limited partners to the state for the tax years of 2021 and 2022. Discussions with the state of North Dakota are ongoing for tax year 2023 and beyond. 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.Comments

35None

~~Index~~Item 1C. Cybersecurity

~~Item~~As a 1Bpart of its risk management strategy, the Board of Directors of the General Partner is actively engaged in overseeing and reviewing the Partnership’s strategic direction and objectives, taking into account, among other considerations, the Partnership’s risk profile and exposure. ~~Unresolved~~Only ~~Staff~~five ~~Comments~~individuals are involved in the Partnership’s day-to-day operations, so the Partnership’s direct business operations are limited. Therefore, the Partnership and the General Partner depend on technology systems to operate its business that are operated and managed by third parties. The Partnership has relationships with a number of third-party business partners and operators who have their own procedures and tools to assist with cybersecurity risk management as well as cybersecurity incident containment and recovery efforts.

~~None~~The Partnership’s cybersecurity risk management program includes consulting with its third parties to monitor the Partnership’s internal and external systems and networks for vulnerabilities, threats and intrusions, and then coordinating a response if a cybersecurity incident is identified. The risk management program also includes facilitating information regarding cybersecurity incidents to the General Partner, so the General Partner can assess necessary action and disclosures.

~~Item 1C.~~ Cybersecurity Risks

AsThe aPartnership ~~part~~has ofnot ~~its~~experienced ~~risk~~any ~~management~~material ~~strategy,~~cybersecurity incidents ~~the~~to ~~Board~~date ofthat ~~Directors~~have ofresulted ~~the General Partner is actively engaged~~ in ~~overseeing~~an ~~and~~interruption ~~reviewing~~to ~~the~~ Partnership’s ~~strategic~~operations ~~direction~~or ~~and~~otherwise ~~objectives,~~had ~~taking~~a ~~into~~material ~~account,~~impact ~~among~~on ~~other~~Partnership ~~considerations~~strategy, financial ~~the~~condition ~~Partnership’s~~or ~~risk~~results ~~profile~~of ~~and exposure~~operations. ~~Only~~For ~~five~~more ~~individuals~~information ~~are~~about ~~involved in~~ the ~~Partnership’s~~cybersecurity ~~day-to-day~~risks ~~operations, so~~ the Partnership’s ~~direct business operations are limited. Therefore~~faces, ~~the~~see ~~Partnership and~~ the ~~General~~risk ~~Partner~~factor entitled ~~depend~~“Cyber-attacks ontargeting ~~technology~~ systems ~~to operate its business that are operated~~ and ~~managed~~infrastructure used by ~~third~~the ~~parties.~~oil ~~The Partnership has relationships with a number of third-party business partners~~ and ~~operators~~natural ~~who~~gas ~~have~~industry ~~their~~may ~~own~~adversely ~~procedures~~impact ~~and~~the ~~tools~~Partnership’s operations” toin ~~assist~~Item ~~with~~IA. ~~cybersecurity~~Risk ~~risk~~Factors ~~management~~of asthis ~~well~~Form ~~as cybersecurity incident containment and recovery efforts~~10-K.

The Partnership’s cybersecurity risk management program includes consulting with its third parties to monitor the Partnership’s internal and external systems and networks for vulnerabilities, threats and intrusions, and then coordinating a response if a cybersecurity incident is identifiedItem 2. ~~The risk management program also includes facilitating information regarding cybersecurity incidents to the General Partner, so the General Partner can assess necessary action and disclosures.~~Properties

~~Cybersecurity~~Information ~~Risks~~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 natural gas Investments, appearing elsewhere within this Annual Report on Form 10-K.

The Partnership has not experienced any material cybersecurity incidents to date that have resulted in an interruption to Partnership operations or otherwise had a material impact on Partnership strategy, financial condition or results of operations. For more information about the cybersecurity risks the Partnership faces, see the risk factor entitled “Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact the Partnership’s operations” in Item IA 3. ~~Risk~~Legal ~~Factors of this Form 10-K.~~Proceedings

~~Item~~At the 2.end ~~Properties~~of the period covered by this Annual Report on Form 10-K, the Partnership was not a party to any material, pending legal proceedings.

~~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~~ 4. ~~Oil~~Mine ~~and~~Safety ~~Gas Investments, appearing elsewhere within this Annual Report on Form 10-K.~~Disclosures

~~Item 3~~Not applicable. ~~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.~~33

~~Item 4. Mine Safety Disclosures~~Index

~~Not applicable.~~Part II

36Item 5. Market For Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

~~Index~~Common Units

~~Part~~As of IIDecember 31, 2024, there were approximately 11.0 million common units outstanding, which were held by approximately 3,600 limited partners. There is currently no established public trading market in which the Partnership’s common units are traded.

~~Item~~Solely to 5assist 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, 2024 of $10.90 ~~Market~~per ~~For~~common ~~Registrant~~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, ~~Common~~custodian’s ~~Equity~~or broker-dealer’s obligations with respect to IRAs or FINRA’s reporting requirements. At December 31, ~~Related~~2024, ~~Shareholder~~the ~~Matters~~Partnership owns an approximate 5.4% non-operated working interest in 447 producing wells, predominantly in McKenzie, Dunn, McLean and ~~Issuer~~Mountrail ~~Purchases~~counties of ~~Equity~~North ~~Securities~~Dakota (collectively, the “Bakken Assets”). The Bakken Assets are operated by third-party operators on behalf of the Partnership and other working interest owners. The average age of the Partnership’s producing wells is approximately 7.6 years.

~~Common~~The fair ~~Units~~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, 2024. The developed per common unit value range is $9.62 – $12.35. 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:

As of December 31, 2023, there were approximately 11.0 million common units outstanding, which were held by approximately 3,600 limited partners. There is currently no established public trading market in which the Partnership’s common units are traded.

(in thousands, except per common unit data)	Estimate at 12/31/24
	(unaudited)

Estimated fair value of oil and natural gas properties	$	121,838
Estimated fair value of cash and cash equivalents		1,464
Estimated fair value of other assets and liabilities, net		1,564
Estimated fair value of outstanding debt		(4,600	)
Estimated fair value of equity	$	120,266

Common units outstanding		11,032

Estimated value per common unit	$	10.90

~~Solely~~Since tothe ~~assist~~Partnership’s ~~trustees~~common ~~and~~units ~~custodians~~are ofnot listed ~~individual~~on ~~retirement~~a ~~accounts~~national ~~(“IRAs”)~~securities ~~containing~~exchange, anno ~~investment~~material inpublic 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 tonatural ~~assist~~gas ~~broker-dealers~~properties was inderived ~~meeting~~from ~~their~~unobservable ~~customer~~inputs ~~account~~and ~~statement~~was ~~reporting~~based ~~obligations~~on ~~under~~the income approach as outlined in Financial ~~Industry~~Accounting ~~Regulatory~~Standards ~~Authority~~Board (“~~FINRA~~FASB”) Accounting ~~rules~~Standards ~~for~~Codification ~~investments~~(“ASC”) inTopic ~~the Partnership~~820, ~~the~~Fair ~~Partnership~~Value isMeasurements ~~providing~~and anDisclosures. ~~estimated~~In ~~per~~the ~~common~~income ~~unit~~approach, the estimated value of the Partnership’s ~~common~~oil ~~units~~and asnatural ofgas ~~December~~properties ~~31,~~was ~~2023~~calculated offrom ~~$11.36~~a ~~per~~discounted ~~common~~cash ~~unit,~~flow asmodel ~~further~~using ~~described~~consolidated projected ~~below.~~cash ~~There~~flows ~~can~~of bethe noPartnership’s ~~assurance~~reserves, ~~that~~as ~~this~~well ~~estimated~~as ~~value~~a ~~per~~discount ~~common~~rate ~~unit~~based on market conditions at December 31, or2024. An ~~the~~additional ~~method~~market-based ~~used~~adjustment was made to ~~estimate~~reflect ~~such~~the ~~value,~~probability ~~complies~~of ~~with~~successful ~~requirements~~future ~~applicable~~development toof athe ~~trustee~~Partnership’s oil and natural gas reserves at December 31, ~~custodian’s~~2024. orThe ~~broker-dealer~~Partnership’s ~~obligations~~cash and cash equivalents are all highly liquid with ~~respect~~maturities of tothree ~~IRAs~~months or ~~FINRA~~less and the fair market value approximates the carrying value. The Partnership’s ~~reporting~~other ~~requirements.~~assets Atand ~~December~~liabilities include ~~31,~~receivables ~~2023,~~from the ~~Partnership~~sale ~~owns~~of anoil, ~~approximate~~natural ~~5.6%~~gas ~~non-operated~~and ~~working~~natural ~~interest~~gas inliquids, ~~422~~accounts ~~producing~~payable ~~wells~~and accrued expenses, ~~predominantly~~which are short-term in ~~McKenzie~~nature, ~~Dunn,~~and ~~McLean~~the carrying value of these assets and ~~Mountrail~~liabilities ~~counties~~approximates offair ~~North~~value ~~Dakota~~at ~~(collectively~~December 31, 2024. The carrying value of the ~~“Bakken~~Partnership’s ~~Assets”).~~outstanding ~~The~~debt ~~Bakken~~was ~~Assets~~considered ~~are~~to ~~operated~~approximate byfair 13value ~~third-party~~at ~~operators~~December 31, 2024 based on ~~behalf~~general market conditions and its maturity. The valuation methodology and calculations were reviewed by management of the Partnership and ~~other~~considered ~~working~~reasonable. The ~~interest~~estimated ~~owners.~~value ~~The~~was ~~average~~not ~~age~~based on an appraisal of the Partnership’s ~~producing wells is approximately 7 years~~assets.

~~The~~As with ~~fair~~any ~~value~~methodology used to estimate ofvalue, the ~~Partnership’s~~methodology ~~common~~employed ~~units~~by the Partnership was based upon aseveral ~~third-party~~estimates ~~valuation,~~and ~~performed~~assumptions that bymay ~~Pinnacle~~not ~~Energy~~be ~~Services~~accurate ofor ~~Oklahoma~~complete ~~City~~and may not accurately reflect future conditions. The estimates and assumptions underlying the estimated value involve judgments with respect to, ~~Oklahoma~~among other things, offuture ~~the~~economic, ~~Partnership’s~~competitive, ~~oil~~regulatory and ~~natural~~financial ~~gas~~market ~~properties~~conditions and future business decisions which may not be realized and ~~management’s~~that ~~estimate~~are ofinherently subject to significant business, economic, competitive and regulatory uncertainties and contingencies, including, among others, risks and uncertainties described in the ~~fair~~periodic ~~value~~reports offiled by the Partnership’s ~~other~~with ~~assets~~the Securities and ~~liabilities~~Exchange asCommission of(“SEC”), ~~December~~all ~~31,~~of ~~2023.~~which ~~The~~are ~~developed~~difficult ~~per~~to ~~common~~predict ~~unit~~and ~~value~~many ~~range~~of which isare ~~$10.26~~beyond –the ~~$12.62.~~control ~~The~~of the Partnership. ~~utilized~~Further, ~~the~~different ~~mid-point~~parties ofusing ~~the~~different assumptions ~~discussed~~and ~~below~~estimates tocould ~~determine~~derive ~~the~~a different estimated value per common unit, ~~above.~~which ~~The~~could ~~following~~be issignificantly adifferent ~~summary~~from of the ~~details~~Partnership’s ofestimated ~~the fair~~ value ~~estimate:~~per common unit.

(in thousands, except per common unit data)	Estimate at 12/31/23
	(unaudited)
Estimated fair value of oil and gas properties	$	122,771
Estimated fair value of cash and cash equivalents		1,456
Estimated fair value of other assets and liabilities, net		1,095
Estimated fair value of equity	$	125,322
Common units outstanding		11,032
Estimated value per common unit	$	11.36

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, 2023. 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, 2023. 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, 2023. 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.Index

37The 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:

~~Index~~● 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 natural 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.

AsThe ~~with~~estimated ~~any methodology used to estimate~~ value, reflects the ~~methodology~~fact ~~employed~~that by the ~~Partnership~~ estimate was ~~based~~calculated ~~upon~~as ~~several~~of ~~estimates~~a ~~and~~point ~~assumptions~~in ~~that~~time. ~~may~~The ~~not~~value beof ~~accurate~~the orPartnership’s ~~complete~~common ~~and~~units ~~may~~will ~~not~~likely ~~accurately~~change ~~reflect~~over ~~future~~time ~~conditions.~~and ~~The~~will ~~estimates~~be ~~and~~influenced by ~~assumptions~~changes ~~underlying~~to the ~~estimated~~ value ~~involve~~of ~~judgments~~individual ~~with respect to~~assets, ~~among~~changes ~~other~~in ~~things,~~the ~~future~~oil ~~economic, competitive, regulatory~~ and ~~financial~~natural ~~market~~gas ~~conditions~~industry, ~~and~~as ~~future~~well ~~business~~as ~~decisions~~changes ~~which may not be realized~~ and ~~that~~developments ~~are~~in ~~inherently~~the energy ~~subject to significant business, economic, competitive~~ and ~~regulatory~~capital ~~uncertainties~~markets. ~~and~~The ~~contingencies,~~Partnership ~~including,~~does ~~among~~not ~~others,~~intend ~~risks~~to ~~and~~update ~~uncertainties~~or ~~described~~otherwise inrevise the ~~periodic~~above ~~reports~~information ~~filed~~to byreflect ~~the~~circumstances existing ~~Partnership~~after ~~with~~ the ~~Securities~~date ~~and~~when ~~Exchange~~made ~~Commission~~or ~~(“SEC”), all of which are difficult~~ to ~~predict~~reflect ~~and many of which are beyond~~ the ~~control~~occurrence of ~~the~~future ~~Partnership. Further~~events, ~~different~~even ~~parties~~in ~~using~~the ~~different~~event ~~assumptions~~that ~~and~~any ~~estimates~~or ~~could~~all ~~derive~~of athe ~~different~~assumptions underlying ~~estimated value per common unit, which could be significantly different from~~ the ~~Partnership’s~~information ~~estimated~~are ~~value~~no ~~per~~longer ~~common unit~~appropriate.

~~The~~Assumptions Used ~~estimated~~in ~~per~~Estimated ~~common~~Value 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~~Common ~~unit, the Partnership can give no assurance that:~~Unit

•As adiscussed ~~limited~~above, ~~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 oil ~~assets~~ and ~~settlement~~natural ofgas ~~its~~properties ~~liabilities~~was ordetermined abased ~~sale~~on ofvarious ~~the~~market ~~Partnership~~level ~~(in~~assumptions, ~~part~~including ~~because~~but ~~estimated values do~~ not ~~necessarily~~limited ~~indicate~~to ~~the~~commodity ~~price at which individual assets or the Partnership could be sold~~market prices, ~~oil~~discount ~~and~~rates ~~gas property values fluctuate~~ and ~~change,~~processing and ~~the~~transportation ~~estimated~~costs. ~~value~~Because ~~may not take into account~~ the ~~expenses associated with such a sale); • the~~ Partnership’s ~~common~~assets ~~units~~are ~~would~~operated ~~trade~~by at13 athird-party operators, ~~price~~some ~~equal~~of ~~to or greater than~~ the ~~estimated~~assumptions ~~value~~will ~~per~~vary ~~common~~by ~~unit~~operator. ifThe ~~they~~following ~~were~~is ~~listed~~a onlist aof ~~national~~key ~~securities~~assumptions ~~exchange;~~used •in the ~~methodology~~calculation ~~used~~of ~~to estimate~~ the estimated value ~~per~~of ~~common~~the ~~unit would be acceptable to FINRA or for compliance with requirements applicable to a trustee~~Partnership’s oroil ~~custodian’s~~and ~~obligations~~natural ~~with~~gas ~~respect~~properties, toa ~~IRAs;~~component ~~or • any or all~~ of the ~~assumptions~~estimated ~~used in estimating the~~ value per common unit ~~will prove to be accurate or complete.~~:

~~The~~● ~~estimated~~NYMEX ~~value~~oil ~~reflects~~strip ~~the~~pricing ~~fact~~as ~~that~~of ~~the~~January ~~estimate~~1, ~~was~~2025, ~~calculated~~which asranges offrom a$69.86 ~~point~~per inbarrel ~~time~~to $63.07 ~~The~~per ~~value~~barrel as of ~~the~~January ~~Partnership’s~~1, ~~common~~2025 ~~units~~to ~~will~~December ~~likely~~31, ~~change~~2029, ~~over time~~ and ~~will~~an beincrease ~~influenced~~of by3% ~~changes~~thereafter towith ~~the~~price ~~value~~cap ofat ~~individual~~$85.00 ~~assets,~~per ~~changes~~barrel in● ~~the~~NYMEX ~~oil and~~ gas ~~industry,~~strip aspricing ~~well~~ as ~~changes~~of ~~and~~January ~~developments~~1, in2025, ~~the~~which ~~energy~~ranges ~~and~~from ~~capital markets~~$3.53 ~~The~~per ~~Partnership~~Mcf ~~does not intend~~ to ~~update~~$3.58 orper ~~otherwise~~Mcf ~~revise~~as ~~the~~of ~~above~~January ~~information~~1, 2025 to ~~reflect~~December ~~circumstances~~31, ~~existing~~2029, ~~after~~and ~~the~~then ~~date~~held ~~when~~flat ~~made~~thereafter orat toa ~~reflect~~price ~~the~~cap ~~occurrence~~ of ~~future~~$4.50 ~~events,~~per ~~even~~Mcf in● ~~the~~Differentials ~~event~~to ~~that~~NYMEX ~~any~~strip orpricing ~~all~~due ofto ~~the~~product ~~assumptions~~processing, ~~underlying~~transportation ~~the~~or ~~information~~contract ~~are no longer appropriate.~~terms

~~Assumptions~~- ~~Used~~Weighted inaverage ~~Estimated~~oil ~~Value~~differential of -$0.99 per ~~Common~~barrel ~~Unit~~of oil - Weighted average natural gas differential of -$0.62 per Mcf of natural gas - Natural gas liquids (NGL) pricing determined using weighted average of -1.2% of NYMEX oil price - Weighted average natural gas shrink of 32% - Weighted average NGL yield of 121.02 barrels per MMcf of wet gas

As● ~~discussed~~Additional ~~above,~~gathering ~~the estimated value of the Partnership’s oil~~ and ~~gas~~processing ~~properties~~(G&P) ~~was~~expenses ~~determined~~subsequently ~~based~~applied onafter ~~various~~differentials ~~market level assumptions, including but not limited~~ to ~~commodity~~NYMEX ~~market~~strip prices, discount rates and processing and transportation costs. Because the Partnership’s assets are operated by 13 third-party operators, some of the assumptions will vary by operator. 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:pricing

•- ~~NYMEX~~Weighted ~~oil~~average ~~strip~~G&P ~~pricing~~expense ason ofthe ~~January~~production 1,and ~~2024,~~sale ~~which~~of ~~ranges~~oil ~~from~~of $715.5354 per barrel to- ~~$62.02~~Weighted ~~per~~average ~~barrel~~G&P asexpense ofon ~~January~~the 1,production ~~2024 to December 31, 2028,~~ and ansale ~~increase~~ of 3%natural ~~thereafter with price cap at $85.00 per barrel • NYMEX~~ gas ~~strip pricing as~~ of ~~January 1, 2024, which ranges from~~ $2.6653 per Mcf to- ~~$3.80~~Weighted ~~per~~average ~~Mcf~~G&P asexpense ofon ~~January~~the 1,production ~~2024 to December 31, 2028,~~ and ~~then~~sale ~~held~~of ~~flat~~NGL ~~thereafter at a price cap~~ of $421.5057 per ~~Mcf~~barrel •of ~~Differentials~~oil ~~to NYMEX strip pricing due to product processing, transportation or contract terms~~equivalent

-● Weighted average ~~oil~~estimate ~~differential~~of gross fixed lease operating expenses per well of +approximately $~~0.51~~6,000 per ~~barrel~~month of● ~~oil~~Total -net ~~Weighted~~variable ~~average~~lease ~~natural~~operating ~~gas~~expenses ~~differential~~estimated at weighted average of +$012.2071 per ~~Mcf~~barrel of ~~natural~~oil ~~gas~~● -Total ~~Natural~~net ~~gas~~variable ~~liquids~~workover ~~(NGL)~~expenses ~~pricing~~estimated ~~determined~~at ~~using~~$3.50 ~~weighted~~per ~~average~~barrel of ~~3.9%~~oil of● ~~NYMEX~~Gross ~~oil~~capital ~~price~~expenditures -to ~~Weighted~~drill ~~average~~and ~~natural~~complete ~~gas~~future ~~shrink~~development oflocations 33estimated between approximately $9.0% -and ~~Weighted~~$11.0 ~~average~~million ~~NGL~~per ~~yield~~well, depending upon operator and length of ~~105~~the well ● Discount rate – 10.260% ~~barrels~~● ~~per~~Risk ~~MMcf~~adjustments ofto ~~wet~~calculated ~~gas~~present value

~~• Additional gathering and processing (G&P) expenses subsequently applied after differentials to NYMEX strip pricing~~35

- Weighted average G&P expense on the production and sale of oil of $5.62 per barrel - Weighted average G&P expense on the production and sale of natural gas of $2.85 per Mcf - Weighted average G&P expense on the production and sale of NGL of $20.32 per barrel of oil equivalentIndex

38- 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% - Proved developed and undeveloped non-consent assets – 50.0%

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

•● ~~Weighted~~An ~~average~~increase ~~estimate~~in the discount rate assumption of ~~gross~~100 ~~fixed~~basis ~~lease~~points ~~operating~~would ~~expenses~~decrease the per ~~well~~common ofunit value range by approximately $~~6,800~~1.21 per ~~month~~common •unit, ~~Total~~all ~~net~~other ~~variable~~assumptions ~~lease~~remaining ~~operating~~the ~~expenses~~same; ~~estimated~~● atA ~~weighted~~decrease ~~average~~in the discount rate assumption of 100 basis points would increase the per common unit value range by approximately $111.1645 per ~~barrel~~common ofunit, all other assumptions remaining the same; ● An increase in the average NYMEX oil •and ~~Total~~natural ~~net~~gas ~~variable~~strip ~~workover~~pricing ~~expenses~~assumptions ~~estimated~~of at500 basis points would increase the per common unit value range by approximately $31.4918 per ~~barrel~~common ofunit, ~~oil~~all •other ~~Gross~~assumptions ~~capital~~remaining ~~expenditures~~the tosame; ~~drill~~● A decrease in the average NYMEX oil and ~~complete~~natural ~~future~~gas ~~development~~strip ~~locations~~pricing ~~estimated~~assumptions ~~between~~of 500 basis points would decrease the per common unit value range by approximately $71.028 ~~and~~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 $~~11.~~0.70 ~~million~~ per ~~well~~common unit, ~~depending~~all ~~upon~~other ~~operator~~assumptions remaining the same; and ~~length~~● ofA ~~the~~decrease ~~well~~of •500 ~~Discount~~basis ~~rate~~points –in ~~10.0%~~the •risk ~~Risk~~adjustment ~~adjustments~~percentage to calculated present value per reserve category would increase the per common unit value range by approximately $0.70 per common unit, all other assumptions remaining the same.

-Incentive Distribution ~~Proved~~Rights 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~~Dealer ~~years~~Manager –Incentive ~~25.0% - Proved undeveloped (POSS) assets to be drilled after ten years – 35.0% - Proved developed and undeveloped non-consent assets – 50.0%~~Fees

AThe ~~change~~General Partner received the Incentive Distribution Rights upon closing of the minimum offering in ~~any~~July 2017. The Dealer Manager also has Dealer Manager Incentive Fees (defined below) where the Dealer Manager could receive distributions up to an additional 4% of gross proceeds of the ~~assumptions~~common ~~would~~units ~~likely~~sold ~~produce~~in athe ~~different~~Partnership’s best-efforts ~~estimated~~offering ~~value~~as ~~per~~outlined in the prospectus for that offering based on the performance of the Partnership. Based on the common units ~~unit~~sold in the Partnership’s best-efforts offering, the Dealer Manager Incentive Fees are approximately $8.7 ~~For~~million, ~~example:~~subject to Payout (defined below).

• An increase in the discount rate assumption of 100 basis points would decrease the per common unit value range by approximately $1.05 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 $1.26 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 $1.04 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 $1.10 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 $0.68 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 $0.68 per common unit, all other assumptions remaining the same.Distribution Policy

The Partnership ~~General~~Agreement ~~Partner~~provides ~~received~~that “Payout” occurs on the ~~Incentive~~day ~~Distribution~~when ~~Rights~~the ~~upon~~aggregate ~~closing~~amount distributed with respect to each of the ~~minimum~~common ~~offering~~units inequals ~~July~~$20.00 ~~2017~~plus the Payout Accrual. The ~~Managing~~Partnership ~~Dealer~~Agreement ~~also~~defines ~~has~~“Payout ~~Dealer~~Accrual” ~~Manager~~as ~~Incentive~~7% ~~Fees~~per ~~(defined~~annum simple ~~below)~~interest ~~where~~accrued ~~the~~monthly ~~Managing~~until ~~Dealer~~paid ~~could~~on ~~receive~~the ~~distributions~~Net upInvestment toAmount anoutstanding ~~additional~~from 4%time ofto ~~gross~~time. ~~proceeds~~The ofPartnership ~~the~~Agreement ~~common~~defines Net ~~units~~Investment ~~sold~~Amount ininitially ~~the~~as ~~Partnership’s~~$20.00 ~~best-efforts~~per ~~offering~~common asunit, ~~outlined~~regardless inof the ~~prospectus~~amount paid for ~~that~~the ~~offering~~common ~~based~~unit. onIf ~~the~~at ~~performance~~any oftime the Partnership. distributes ~~Based~~to onholders ~~the~~of common units ~~sold~~more inthan the ~~Partnership’s~~Payout ~~best-efforts offering~~Accrual, the ~~Dealer~~amount ~~Manager~~the ~~Incentive~~Partnership ~~Fees~~distributes ~~are~~in ~~approximately~~excess ~~$8.7~~of ~~million,~~the ~~subject~~Payout toAccrual will ~~Payout~~reduce ~~(defined~~the ~~below)~~Net Investment Amount.

~~Distribution~~In June ~~Policy~~2023, the General Partner declared and paid a special distribution to return $1.60 per common unit of capital to holders of Partnership common units. As described in Income Tax in Note 2. Summary of Significant Accounting Policies in Part II, Item 8 of this Form 10-K, in May 2023 and April 2024, the Partnership paid total withholding taxes of approximately $0.09 per common unit to the state of North Dakota on behalf of its limited partners related to tax years 2021, 2022 and 2023. These withholding tax payments, along with the $1.60 per common unit special distribution to holders of its common units in June 2023, have reduced the Net Investment Amount described above by an approximate total of $1.69 per common unit.

~~Prior to “Payout,” which is defined below, all of the~~ All distributions made by the Partnership, ifafter ~~any~~Payout, ~~will~~which bemay ~~paid~~include toall ~~the~~or ~~holders~~a portion of ~~common~~the ~~units.~~proceeds ~~Accordingly,~~of the ~~Partnership~~sale ~~will~~of ~~not~~all ~~make~~or ~~any~~substantially all ~~distributions~~of ~~with respect to~~ the ~~Incentive~~Partnership’s ~~Distribution~~assets, ~~Rights and~~ will ~~not~~be ~~pay~~made ~~the~~as ~~Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.~~follows:

~~The~~● ~~Partnership~~First, ~~Agreement~~(i) ~~provides~~to ~~that~~the ~~“Payout”~~Record ~~occurs~~Holders onof the ~~day~~Incentive ~~when~~Distribution ~~the~~Rights, ~~aggregate~~30%; ~~amount~~(ii) ~~distributed with respect~~ to ~~each of~~ the ~~common~~Dealer ~~units~~Manager, ~~equals $20.00 plus~~ the ~~Payout~~“Dealer ~~Accrual.~~Manager ~~The~~Incentive ~~Partnership Agreement defines “Payout Accrual~~Fees”, ~~as 7~~30%, ~~per annum simple interest accrued monthly~~ until ~~paid~~such ~~on the Net Investment Amount outstanding from~~ time ~~to time. The Partnership Agreement defines Net Investment Amount initially~~ as ~~$20.00~~the ~~per~~Dealer ~~common~~Manager ~~unit,~~receives ~~regardless~~4% of the ~~amount~~gross ~~paid~~proceeds ~~for~~of the common ~~unit.~~units Ifsold; atand ~~any~~(iii) ~~time~~to the ~~Partnership~~Record ~~distributes~~Holders ~~to holders~~ of outstanding common units, ~~more than the Payout Accrual~~40%, ~~the~~pro ~~amount~~rata ~~the~~based ~~Partnership~~on ~~distributes~~their inpercentage ~~excess of the Payout Accrual will reduce the Net Investment Amount~~interest.

In June 2023, the General Partner declared and paid a special distribution to return $1.60 per common unit of capital to holders of Partnership common units. In addition, in May 2023, the Partnership paid a withholding tax of approximately $0.03 per common unit to the state of North Dakota on behalf of its limited partners related to tax year 2021. This withholding tax payment, along with the $1.60 per common unit special distribution to holders of its common units in June 2023, has reduced the Net Investment Amount described above by an approximate total of $1.63 per common unit.36

39Index

~~Index~~● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

All items ~~distributions~~of ~~made~~income, ~~by the Partnership after Payout~~gain, ~~which~~loss ~~may~~and ~~include~~deduction ~~all~~will orbe aallocated ~~portion~~to ofeach ~~the~~Partner’s ~~proceeds~~capital ofaccount ~~the~~in ~~sale~~a ofmanner ~~all~~generally orconsistent with ~~substantially all of~~ the ~~Partnership’s~~distribution ~~assets,~~procedures ~~will~~outlined ~~be made as follows:~~above.

~~● First, (i) to~~ For the ~~Record~~year ~~Holders~~ended ofDecember ~~the~~31, ~~Incentive Distribution Rights~~2024, ~~30%;~~the ~~(ii)~~Partnership todeclared ~~the~~and ~~Managing~~paid ~~Dealer,~~distributions ~~the~~of ~~“Dealer~~$1.282163 ~~Manager~~per ~~Incentive~~common ~~Fees”~~unit, ~~30%,~~or ~~until~~$14.1 ~~such~~million. ~~time as~~ For the ~~Managing~~year ~~Dealer~~ended ~~receives~~December 4%31, of2023, the ~~gross~~Partnership ~~proceeds~~declared ~~of the common units sold;~~ and ~~(iii)~~paid todistributions ~~the Record Holders~~ of ~~outstanding~~$2.939163 per common ~~units~~unit, ~~40%,~~or ~~pro~~$32.4 ~~rata based on their percentage interest~~million.

~~● Thereafter, (i) to~~ Neither the ~~Record~~Partnership ~~Holders~~nor of the ~~Incentive~~General ~~Distribution~~Partner ~~Rights,~~has ~~60%;~~adopted ~~and~~an ~~(ii)~~equity tocompensation ~~the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest~~plan.

~~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~~Item 6. [Reserved]

~~For the year ended December 31, 2023, the Partnership paid distributions of $2~~Not applicable.~~939163 per common unit, or $32.4 million. For the year ended December 31, 2022, the Partnership paid distributions of $1.396164 per common unit, or $15.4 million.~~

~~Neither~~Item 7. ~~the~~Management’s ~~Partnership~~Discussion ~~nor~~and ~~the~~Analysis ~~General~~of ~~Partner~~Financial ~~has~~Condition ~~adopted~~and anResults ~~equity~~of ~~compensation plan.~~Operations

The following discussion and analysis should be read in conjunction with Item 6.8 ~~[Reserved]~~– 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.

~~Not applicable.~~Overview

~~Item~~Energy Resources 712, L.P. ~~Management~~(the “Partnership”) was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership began offering common units of limited partner interest (the “common units”) on a best-efforts basis on May 17, 2017, the date the Partnership’s ~~Discussion~~initial Registration Statement on Form S-1 (File No. 333-216891) was declared effective by the Securities and ~~Analysis~~Exchange Commission. The Partnership completed its best-efforts offering on October 24, 2019. Total common units sold were approximately 11.0 million for gross proceeds of ~~Financial~~$218.0 ~~Condition~~million and ~~Results~~proceeds net of ~~Operations~~offering costs of $204.3 million.

The general ~~following~~partner ~~discussion~~is ~~and~~Energy ~~analysis~~Resources ~~should~~12 beGP, ~~read~~LLC in(the ~~conjunction~~“General ~~with~~Partner”). ~~Item~~The 8General –Partner manages the ~~Consolidated~~day-to-day ~~Financial~~affairs of ~~Statements~~the ~~and~~Partnership. ~~Notes~~All ~~thereto,~~decisions regarding the ~~introduction~~management of ~~Part~~the IPartnership ~~regarding~~made ~~“Forward-Looking~~by ~~Statements,”~~the ~~and~~General ~~Item~~Partner 1Aare –made ~~Risk~~by ~~Factors~~the ~~appearing~~Board ~~elsewhere~~of inDirectors of ~~this~~the ~~Annual~~General ~~Report~~Partner onand ~~Form~~its ~~10-K~~officers. The Partnership has no officers, directors or employees.

~~Overview~~The Partnership was formed to acquire primarily oil and natural gas properties located onshore in the United States. On February 1, 2018, the Partnership completed its first purchase (“Acquisition No. 1”) in the Williston Basin of North Dakota, acquiring, at closing, non-operated working interests in producing wells and in-process wells, along with additional future development locations, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”), for $87.5 million, subject to customary adjustments. On August 31, 2018, the Partnership closed on its second asset purchase (“Acquisition No. 2”), acquiring an additional non-operated working interest in the Bakken Assets for $82.5 million, subject to customary adjustments. Prior to these acquisitions, the Partnership owned no oil and natural gas assets. The Partnership utilized proceeds from its best-efforts offering and available financing to close on the acquisitions.

~~Energy Resources 12, L.P. (the “Partnership”) was formed as~~ As a ~~Delaware~~result ~~limited~~of ~~partnership.~~these ~~The~~acquisitions ~~initial~~and ~~capitalization~~completed ofdrilling during the ~~Partnership~~period of $1ownership,~~000~~ ~~occurred~~as onof December 3031, ~~2016. The Partnership began offering common units of limited partner interest (the “common units”) on a best-efforts basis on May 17~~2023, ~~2017,~~ the ~~date the~~ Partnership’s ownership ~~initial~~of ~~Registration~~the ~~Statement~~Bakken onAssets ~~Form~~consisted ~~S-1~~of ~~(File~~an Noapproximate 5.6% ~~333~~non-~~216891)~~operated ~~was~~working ~~declared~~interest ~~effective~~in by422 ~~the~~producing ~~Securities~~wells, ~~and~~an ~~Exchange~~estimated ~~Commission~~approximate 5.5% ~~The Partnership completed its best~~non-~~efforts~~operated ~~offering~~working oninterest ~~October~~in ~~24,~~8 ~~2019.~~wells ~~Total~~in ~~common~~various ~~units~~stages ~~sold were approximately 11.0 million for gross proceeds~~ of ~~$218.0~~the ~~million~~drilling and ~~proceeds~~completion ~~net~~process ofand ~~offering~~additional ~~costs~~possible offuture development ~~$204~~locations.~~3 million.~~

The Bakken ~~general~~Assets ~~partner~~are isoperated ~~Energy~~by ~~Resources~~multiple 12third-party GPoperators, ~~LLC~~including ~~(the~~Devon ~~“General~~Energy ~~Partner”).~~Corporation, ~~The~~Marathon ~~General~~Oil, ~~Partner~~EOG ~~manages~~Resources, ~~the~~Continental Resources ~~day-to-day affairs of the Partnership. All decisions regarding the management of the Partnership made by the General Partner are made by the Board of Directors of the General Partner~~ and ~~its~~Chord ~~officers~~Energy. ~~The Partnership has no officers, directors or employees.~~

~~The~~Current Price Partnership was formed to acquire primarily oil and gas properties located onshore in the United States. On February 1, 2018, the Partnership completed its first purchase (“Acquisition No. 1”) in the Williston Basin of North Dakota, acquiring, at closing, non-operated working interests in producing wells and in-process wells, along with additional future development locations, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”), for $87.5 million, subject to customary adjustments. On August 31, 2018, the Partnership closed on its second asset purchase (“Acquisition No. 2”), acquiring an additional non-operated working interest in the Bakken Assets for $82.5 million, subject to customary adjustments. Prior to these acquisitions, the Partnership owned no oil and natural gas assets. The Partnership utilized proceeds from its best-efforts offering and available financing to close on the acquisitions.Environment

AsOil, natural agas ~~result~~and natural gas liquids (“NGL”) prices are determined by many factors outside of ~~these~~the ~~acquisitions~~Partnership’s control. Historically, world-wide oil and ~~completed~~natural ~~drilling~~gas ~~during~~prices and markets have been subject to significant change and may continue to be in the future. ~~period~~Global ofmacroeconomic ~~ownership,~~factors ascontributing to uncertainty within the industry include real or perceived geopolitical risks in oil-producing regions of ~~December~~the 31world, ~~2023,~~particularly Russia and the ~~Partnership’s~~Middle ~~ownership~~East; forecasted levels of ~~the~~global ~~Bakken~~economic ~~Assets~~growth ~~consisted~~combined with forecasted global supply; supply levels of anoil ~~approximate~~and ~~5.6%~~natural ~~non-operated~~gas ~~working~~due ~~interest~~to inexploration ~~422~~and ~~producing~~development ~~wells,~~activities anin ~~estimated~~the ~~approximate~~United ~~5.5%~~States; ~~non-operated~~environmental and ~~working~~climate ~~interest~~change inregulation; 8actions ~~wells~~taken inby ~~various~~the ~~stages~~Organization of the ~~drilling~~Petroleum ~~and~~Exporting ~~completion~~Countries ~~process~~(“OPEC”); and ~~additional~~the ~~possible~~strength of ~~future~~the ~~development~~U.S. ~~locations~~dollar in international currency markets.

40The length and outcome of the military conflict between Ukraine and Russia as well as the continued unrest in the Middle East are highly unpredictable, and further escalation of these conflicts could lead to significant market and other disruptions, such as volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability and other material and adverse effects on macroeconomic conditions. The short- and long-term impact of these conflicts on the operations and financial condition of the Partnership and the global economy is uncertain.

~~Index~~37

The Bakken Assets are operated by 13 third-party operators, including Devon Energy Corporation (NYSE: DVN), Marathon Oil (NYSE: MRO), EOG Resources (NYSE: EOG), Continental Resources (NYSE: CLR) and Chord Energy (NASDAQ: CHRD).Index

~~Current~~The ~~Price~~following ~~Environment~~table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2024 and 2023.

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.

	Year Ended December 31,				Percent
	2024		2023		Change
Average market closing prices ⁽¹⁾
Oil (per Bbl)	$	75.76	$	77.60		-2.4	%
Natural gas (per Mcf)	$	2.37	$	2.53		-6.3	%

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 start of the military conflict between Russia and Ukraine in March 2022 (~~which remains ongoing~~1), ~~related~~Based ~~economic sanctions imposed~~ on ~~Russia~~average ~~and~~NYMEX ~~additional~~futures ~~production~~closing ~~growth~~prices ~~by OPEC further exacerbated supply shortages, causing~~ (oil) ~~prices to peak at over $120 per barrel during the second quarter of 2022. Persistent concerns about a recession~~ and ~~short-term~~NYMEX/Henry ~~softening~~Hub ofspot ~~global and domestic demand contributed to lower commodity~~ prices ~~during~~(natural the first half of 2023. Oil prices rebounded to 12-month highs late in September 2023 at over $90 per barrel, primarily due to Saudi Arabia and Russia continuing their commitments to production cuts. However, a surge in exports from U.S. producers in the fourth quarter of 2023, along with weakening global demand, led to oil prices falling close to $70 per barrel by year end.gas)

OnAs ~~October~~specified 7,by ~~2023~~the SEC, the ~~conflict~~prices ~~between~~for ~~Israel~~oil, natural gas and ~~Palestinian~~NGL ~~territories~~used ~~was~~to ~~reignited~~calculate ~~when~~the ~~Hamas,~~Partnership’s areserves ~~militant~~are ~~group~~based inon ~~control~~the ofunweighted ~~Gaza,~~arithmetic ~~carried~~average ~~out~~prices aas ~~surprise~~of ~~attack~~the onfirst ~~Israeli~~day of ~~cities~~each ~~and~~of ~~towns near~~ the ~~Gaza~~twelve ~~strip.~~months ~~Both~~during ~~sides~~the ~~have~~years ~~been~~ended inDecember ~~constant~~31, ~~combat~~2024 ~~since~~and 2023. The ~~length~~average realized oil, natural gas and ~~outcome~~NGL ofprices, including the ~~military~~effect ~~conflicts~~of ~~between~~price ~~Ukraine~~differential ~~and~~adjustments, ~~Russia~~used asin ~~well~~computing the Partnership’s reserves as ~~Israel~~of ~~and~~December ~~Hamas~~31, ~~are~~2024 ~~highly~~were $75.33 ~~unpredictable~~per barrel of oil, $1.43 per MMcf of natural gas and ~~further~~$0.49 ~~escalation~~per barrel of ~~these~~NGL. ~~conflicts~~The ~~could~~average ~~lead~~realized tooil, ~~significant~~natural ~~market~~gas and ~~other~~NGL ~~disruptions~~prices, including ~~such~~the aseffect ~~volatility~~of price differential adjustments, used in ~~commodity~~computing ~~prices~~the ~~and~~Partnership’s ~~supply~~reserves as of ~~energy~~December ~~resources~~31, ~~instability~~2023 inwere $78.53 ~~financial~~per ~~markets~~barrel of oil, ~~supply~~$2.81 ~~chain~~per ~~interruptions,~~MMcf ~~political~~of natural gas and ~~social~~$2.29 ~~instability~~per ~~and~~barrel ~~other~~of ~~material~~NGL. ~~and~~See ~~adverse~~“Note ~~effects~~8 — Supplementary Information on ~~macroeconomic~~Oil, ~~conditions~~Natural Gas and Natural Gas Liquid Reserves (Unaudited)” in Part II, Item 8. ~~The~~Financial ~~short-~~Statements and ~~long-term~~Supplementary ~~impact~~ Data” of ~~these~~this ~~conflicts~~Form 10-K for more information on the ~~operations~~oil, natural gas and ~~financial~~NGL ~~condition~~prices ofused in computing the Partnership’s ~~and~~reserves ~~the~~as ~~global~~of December ~~economy~~31, is2024 ~~uncertain~~and 2023.

~~The~~Results ~~following~~of ~~table~~Operations ~~lists average NYMEX prices~~ for ~~oil~~Years ~~and~~2024 ~~natural gas for the years ended December 31, 2023~~ and ~~2022.~~2023

	Year Ended December 31,				Percent
	2023		2022		Change
Average market closing prices (1)
Oil (per Bbl)	$	77.60	$	94.33		-17.7	%
Natural gas (per Mcf)	$	2.53	$	6.45		-60.8	%

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.

~~(1)~~The ~~Based~~following ontable ~~average~~is ~~NYMEX~~a ~~futures~~summary ~~closing~~of ~~prices~~the ~~(oil)~~results from ~~and~~operations, ~~NYMEX/Henry~~including ~~Hub~~production, ~~spot~~of ~~prices~~the ~~(natural~~Partnership’s ~~gas)~~non-operated working interest in the Bakken Assets for the years ended December 31, 2024 and 2023.

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, 2023 and 2022. 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, 2023 were $78.53 per barrel of oil, $2.81 per MMcf of natural gas and $2.29 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, 2022 were $94.41 per barrel of oil, $6.54 per MMcf of natural gas and $20.67 per barrel of NGL. See “Note 7 — 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, 2023 and 2022.

	Year Ended December 31,
	2024		Percent of Revenue			2023		Percent of Revenue			Percent Change
Total revenues	$	36,118,140		100.0	%	$	48,627,263		100.0	%		-25.7	%
Production expenses		17,670,082		48.9	%		20,398,873		41.9	%		-13.4	%
Production taxes		2,923,118		8.1	%		4,113,774		8.5	%		-28.9	%
Depreciation, depletion, amortization and accretion		17,823,407		49.3	%		18,269,818		37.6	%		-2.4	%
General and administrative expenses		2,198,954		6.1	%		2,306,507		4.7	%		-4.7	%

Sold production (BOE):
Oil		421,815					549,241					-23.2	%
Natural gas		176,373					182,084					-3.1	%
Natural gas liquids		156,667					168,906					-7.2	%
Total		754,855					900,231					-16.1	%

Average sales price per unit:
Oil (per Bbl)	$	74.02				$	77.13					-4.0	%
Natural gas (per Mcf)		1.45					2.52					-42.5	%
Natural gas liquids (per Bbl)		21.45					20.80					3.1	%
Combined (per BOE)		47.85					54.02					-11.4	%

Average unit cost per BOE:
Production expenses		23.41					22.66					3.3	%
Production taxes		3.87					4.57					-15.3	%
Depreciation, depletion, amortization and accretion		23.61					20.29					16.3	%

Capital expenditures	$	2,826,249				$	9,961,331

~~Results of Operations for Years 2023 and 2022~~38

41Oil, natural gas and NGL revenues

~~Index~~For the years ended December 31, 2024 and 2023, revenues for oil, natural gas and NGL sales were $36.1 million and $48.6 million, respectively. Revenues for the sale of crude oil were $31.2 million and $42.4 million, respectively, which resulted in realized prices of $74.02 and $77.13 per barrel, respectively. Revenues for the sale of natural gas were $1.5 million and $2.8 million, respectively, which resulted in realized prices of $1.45 and $2.52 per Mcf, respectively. Revenues for the sale of NGLs were $3.4 million and $3.5 million, respectively, which resulted in realized prices of $21.45 and $20.80 per BOE, respectively. Average realized prices in the fourth quarter of 2024 were approximately $67.50 per barrel of oil, $1.76 per Mcf of natural gas and $21.74 per BOE of NGL, compared to the fourth quarter of 2023 prices of approximately $77.42 per barrel of oil, $2.13 per Mcf of natural gas and $19.84 per BOE of NGL.

~~The~~Production volumes per day fluctuate due to the timing of well completions; new wells often have high levels of production immediately following ~~table~~completion, isthen adecline ~~summary~~to more consistent levels as the wells age. The Partnership turned 20 new wells sales during the second and third quarters of 2024, which helped offset the ongoing impact of adverse weather conditions in North Dakota during a multi-day stretch in mid-January that led to suspended production throughout the Bakken during 2024. The Partnership’s results ~~from~~for ~~operations~~the three and nine months ended September 30, ~~including~~2023 were also positively impacted by the completion of 27 new wells that were turned to sales during the fourth quarter of 2022 through the third quarter of 2023. Sold production for the Bakken Assets was approximately 2,100 ofBOE per day for the year ended December 31, 2024. The Partnership’s ~~non~~results for the year ended December 31, 2023 were positively impacted by the completion of 27 new wells that were turned to sales during the fourth quarter of 2022 through the third quarter of 2023. The completion of these new wells provided an increase to year-~~operated~~to-date ~~working~~2023 ~~interest~~production, inwith sold production for the Bakken Assets approximating 2,500 BOE per day for the ~~years~~ year ended December 31, 2023. Sold production was approximately 2,000 BOE per day and ~~2022~~2,200 BOE per day for fourth quarters of 2024 and 2023, respectively.

	Year Ended December 31,
	2023		Percent of Revenue			2022		Percent of Revenue			Percent Change
Total revenues	$	48,627,263		100.0	%	$	58,148,401		100.0	%		-16.4	%
Production expenses		20,398,873		41.9	%		16,367,549		28.1	%		24.6	%
Production taxes		4,113,774		8.5	%		4,698,786		8.1	%		-12.5	%
Depreciation, depletion, amortization and accretion		18,269,818		37.6	%		13,720,213		23.6	%		33.2	%
General and administrative expenses		2,306,507		4.7	%		2,393,441		4.1	%		-3.6	%
Sold production (BOE):
Oil		549,241					503,925					9.0	%
Natural gas		182,084					154,630					17.8	%
Natural gas liquids		168,906					141,495					19.4	%
Total		900,231					800,050					12.5	%
Average sales price per unit:
Oil (per Bbl)	$	77.13				$	94.00					-17.9	%
Natural gas (per Mcf)		2.52					6.45					-60.9	%
Natural gas liquids (per Bbl)		20.80					33.93					-38.7	%
Combined (per BOE)		54.02					72.68					-25.7	%
Average unit cost per BOE:
Production expenses		22.66					20.46					10.8	%
Production taxes		4.57					5.87					-22.2	%
Depreciation, depletion, amortization and accretion		20.29					17.15					18.3	%
Capital expenditures	$	9,961,331				$	11,735,200

In conjunction with commodity market pricing, the Partnership’s results for the year ended December 31, 2024 were negatively impacted by lower market commodity prices as well as reduced realized sales prices for oil (see Differentials below), when compared to the year ended December 31, 2023. In addition, continued high inventories kept natural gas prices low throughout the majority of 2024. 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.

~~Oil~~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 of the Bakken Assets may curtail daily production, shut-in producing wells or seek other cost-cutting measures. Consequently, any of these measures could significantly impact the Partnership’s oil, natural gas and NGL ~~revenues~~production, and there can be no assurance regarding how they will produce if and when they are brought back on-line. Further, production is dependent on the investment in existing wells and the development of new wells. See further discussion on the Partnership’s investment in new wells in “Liquidity and Capital Resources” below.

For the years ended December 31, 2023 and 2022, revenues for oil, natural gas and NGL sales were $48.6 million and $58.1 million, respectively. Revenues for the sale of crude oil were $42.4 million and $47.4 million, respectively, which resulted in realized prices of $77.13 and $94.00 per barrel, respectively. Revenues for the sale of natural gas were $2.8 million and $6.0 million, respectively, which resulted in realized prices of $2.52 and $6.45 per Mcf, respectively. Revenues for the sale of NGLs were $3.5 million and $4.8 million, respectively, which resulted in realized prices of $20.80 and $33.93 per BOE, respectively. Average realized prices in the fourth quarter of 2023 were approximately $77.42 per barrel of oil, $2.13 per Mcf of natural gas and $19.84 per BOE of NGL, compared to the fourth quarter of 2022 prices of approximately $83.72 per barrel of oil, $5.70 per Mcf of natural gas and $23.06 per BOE of NGL.Differentials

~~Production~~The ~~volumes~~realized prices per ~~day~~barrel ~~fluctuate due to the timing~~ of ~~well~~oil ~~completions;~~above ~~new~~are based ~~wells~~upon ~~often~~the ~~have~~NYMEX ~~high~~benchmark ~~levels~~price ofless ~~production~~a ~~immediately~~cost ~~following completion, then decline~~ to ~~more~~distribute ~~consistent~~the ~~levels~~oil, asor the ~~wells age~~differential. ~~The~~Oil ~~Partnership’s~~price ~~results~~differentials ~~for~~primarily represent the ~~year~~transportation ~~ended~~costs ~~December~~in ~~31,~~moving ~~2023~~produced ~~were~~oil ~~positively~~at ~~impacted by~~ the ~~completion~~wellhead ofto 27a ~~new~~refinery ~~wells~~and ~~that~~are ~~were~~based ~~turned~~on ~~to sales during~~ the ~~fourth~~availability ~~quarter~~ of ~~2022~~pipeline, ~~through~~rail ~~the~~and other ~~third~~transportation ~~quarter~~methods ofout ~~2023. The completion~~ of ~~these~~the ~~new~~Bakken. ~~wells~~Oil ~~provided~~price andifferentials ~~increase~~ to ~~year-to-date~~the ~~2023~~NYMEX ~~production,~~benchmark ~~with~~price ~~sold~~vary ~~production~~by ~~for~~operator ~~the~~based ~~Bakken~~upon ~~Assets~~operator-specific contracts. ~~approximating~~On 2average,~~500~~ ~~BOE per day for~~ the ~~year~~Partnership’s ~~ended~~realized ~~December~~oil ~~31,~~price ~~2023,~~differentials ~~compared~~were ~~to 2,200 BOE per day in 2022. Sold production was~~ approximately ~~2,200~~$1 ~~BOE~~ per ~~day~~barrel ~~and 2,800 BOE per day for fourth quarters~~ of ~~2023~~oil ~~and~~higher ~~2022,~~during the ~~respectively.~~year Asended of December 31, ~~2023~~2024, ~~the Partnership has eight (8) wells~~ in ~~various~~comparison ~~stages of the drilling and completion process, and due~~ to ~~the~~year ~~Partnership’s~~ended ~~ownership~~December ~~percentage~~31, certain of these wells are expected to significantly contribute to sold production volumes upon completion. The Partnership has also elected to participate in an additional 16 wells during the first quarter of 20242023, which ~~will~~reduced ~~provide incremental production to offset~~ the ~~natural declines in production volumes; the~~ Partnership’s ~~average~~realized ~~non-operated~~oil ~~working interest in these 16 wells is approximately 1%~~sales prices.

The ~~increase~~Dakota inAccess ~~sold~~Pipeline ~~production~~is ~~volumes~~a ~~were~~significant ~~offset~~pipeline that bytransports ~~decreases in market prices of~~ oil and natural gas ~~when~~from ~~compared~~North toDakota ~~2022,~~fields. ofIts ~~which~~use ~~the~~by ~~factors~~operators ~~for~~in the ~~reduction~~region inis ~~market~~currently ~~prices~~in ~~were~~ongoing ~~discussed~~litigation in the ~~Current~~United ~~Price~~States. ~~Environment~~If ~~above.~~use ~~The~~of ~~Partnership’s~~the ~~realized~~Dakota ~~sales~~Access ~~prices~~Pipeline ~~for~~or ~~NGLs~~any ~~are~~other ~~influenced~~pipelines byservicing the ~~components~~region ~~extracted,~~are ~~including~~suspended ~~ethane~~at a future date, ~~propane~~the disruption ~~and~~of ~~butane~~transporting ~~and~~the ~~natural~~Partnership’s ~~gasoline,~~production ~~among~~out ~~others,~~of ~~and~~North Dakota could negatively impact the ~~respective~~Partnership’s ~~market~~realized sales ~~pricing~~prices, ~~for~~results ~~each~~of ~~component~~operations and/or cash flows.

4239

Index

IfOperating ~~commodity~~costs ~~prices fall from current levels~~ and operators are unable to produce, process and sell oil and natural gas at economical prices, the operators of the Bakken Assets may curtail daily production, shut-in producing wells or seek other cost-cutting measures. Consequently, any of these measures could significantly impact the Partnership’s oil, natural gas and NGL production, and there can be no assurance regarding how they will produce if and when they are brought back on-line. Further, production is dependent on the investment in existing wells and the development of new wells. See further discussion on the Partnership’s investment in new wells in “Liquidity and Capital Resources” below.expenses

~~Differentials~~Production expenses

~~The~~Production ~~realized~~expenses ~~prices per barrel of oil above~~ are ~~based~~daily ~~upon~~costs incurred by the ~~NYMEX~~Partnership ~~benchmark~~to ~~price~~bring ~~less~~oil aand ~~cost~~natural togas ~~distribute~~out ~~the~~of ~~oil, or~~ the ~~differential.~~ground ~~Oil~~and ~~price~~to ~~differentials~~market, ~~primarily~~along ~~represent~~with the ~~transportation~~daily costs inincurred ~~moving~~to ~~produced~~maintain ~~oil~~producing properties. atSuch ~~the~~costs ~~wellhead~~include tofield apersonnel ~~refinery~~compensation, ~~and~~saltwater ~~are~~disposal, ~~based~~utilities, ~~on the availability of pipeline~~maintenance, ~~rail~~repairs and ~~other~~servicing ~~transportation~~expenses related ~~methods out of the Bakken. Oil price differentials~~ to the ~~NYMEX benchmark price vary by operator based upon operator-specific contracts. The~~ Partnership’s ~~realized~~ oil ~~sales~~and ~~prices~~natural ~~dropped~~gas ~~approximately 18% in 2023 from 2022 realized sales pricing~~properties, ~~which~~along ~~is in line~~ with the ~~decline~~gathering inand ~~NYMEX~~processing ~~market~~contract ~~oil~~in ~~prices~~effect ~~from 2022 to 2023, so despite macroeconomic factors putting downward pressure on market pricing~~ for ~~oil during 2023~~the extraction, ~~the~~transportation ~~Partnership’s~~and ~~oil~~treatment ~~price~~of ~~differentials~~natural ~~have only been marginally impacted~~gas.

~~The~~For ~~Dakota~~the ~~Access~~years ~~Pipeline~~ended isDecember a31, ~~significant~~2024 ~~pipeline~~and ~~that~~2023, production ~~transports~~expenses ~~oil~~were $17.7 million and ~~natural~~$20.4 ~~gas~~million, ~~from~~and ~~North~~production ~~Dakota~~expenses ~~fields~~per BOE of sold production were $23.41 ~~Its~~and ~~use~~$22.66, byrespectively. Production ~~operators~~expenses infor the ~~region~~fourth isquarters ~~currently~~of in2024 ~~ongoing~~and ~~litigation~~2023 inwere ~~the~~$4.1 ~~United~~million ~~States~~and $4.7 Ifmillion, ~~use~~respectively, ofand ~~the~~production ~~Dakota~~expenses per ~~Access~~BOE ~~Pipeline~~of orproduction ~~any~~were ~~other~~$22.83 ~~pipelines~~and ~~servicing~~$23.26, ~~the~~respectively. ~~region~~The ~~are~~Partnership’s ~~suspended~~lease atoperating aexpenses ~~future~~have ~~date~~been lower during 2024, and ~~the~~due ~~disruption~~to lower sold production of ~~transporting~~natural ~~the~~gas ~~Partnership’s~~and ~~production~~NGLs, ~~out~~compared ofto ~~North~~2023, ~~Dakota~~marketing ~~could~~and ~~negatively~~selling ~~impact~~costs ~~the~~have ~~Partnership’s~~also ~~realized~~decreased ~~sales~~in ~~prices~~2024. However, production ~~results~~expenses ofper ~~operations~~BOE increased in 2024 compared to 2023 primarily due to higher year-to-date workover expenses and~~/or~~ ~~cash~~overall ~~flows~~lower sold production volumes, which decreases the production base over which fixed costs are spread.

~~Operating~~Production ~~costs and expenses~~taxes

Taxes on the production and extraction of oil and natural 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 NGL to total sales. Production ~~expenses~~taxes for the years ended December 31, 2024 and 2023 were $2.9 million (8% of revenue) and $4.1 million (9% of revenue), respectively. Production taxes for the fourth quarters of 2024 and 2023 were $0.6 million (8% of revenue) and $0.9 million (8% of revenue), respectively. Oil production comprised approximately 56% and 61%, respectively, of the Partnership’s sold production volumes in the years ended December 31, 2024 and 2023, respectively.

~~Production~~General ~~expenses are daily costs incurred by the Partnership to bring oil~~ and ~~natural~~administrative 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~~General and administrative costs for the years ended December 31, ~~2023~~2024 and ~~2022,~~2023 ~~production expenses~~ were $202.42 million and $162.43 million, ~~and~~respectively. ~~production~~The ~~expenses~~principal ~~per~~components ~~BOE~~ of ~~sold~~general ~~production~~and ~~were~~administrative expense ~~$22.66~~are ~~and $20.46~~accounting, ~~respectively. Production expenses per BOE increased in 2023~~legal, ~~in comparison to 2022~~advisory, ~~primarily~~consulting ~~due to due to (1) lease operating expenses remaining high from increased activity of newly completed wells; (2) persistent inflation;~~ and ~~(3)~~management ~~higher gathering and processing expenses required to sell through natural gas and NGLs when market prices are low~~fees.

~~Production expenses for the fourth quarters of 2023 and 2022 were $4.7 million and $4.5 million~~Depreciation, ~~respectively~~depletion, ~~and~~amortization ~~production expenses per BOE of production were $23.26~~ and ~~$17.53,~~accretion respectively. Production expenses for BOE increased in the fourth quarter of 2023, in comparison to the fourth quarter of 2022, primarily due to a decrease in sold production volumes along with higher fixed lease operating expenses.(“DD&A”)

~~Production~~DD&A ~~taxes~~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. The Partnership’s DD&A for the years ended December 31, 2024 and 2023 was $17.8 million and $18.3 million, respectively, and DD&A per BOE of production was $23.61 and $20.29, respectively. DD&A for the fourth quarters of 2024 and 2023 was $4.1 million and $4.6 million, respectively, and DD&A per BOE of production was $23.00 and $22.74, respectively.

~~Taxes~~The onincrease ~~the~~in ~~production~~DD&A ~~and~~expense ~~extraction~~per ofBOE ~~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 for ~~taxes as a percentage of revenue may fluctuate dependent upon~~ the ~~ratio~~quarter ~~of sales of natural gas~~ and ~~NGL~~year ~~to total sales. Production taxes for the years~~ ended December 31, ~~2023 and 2022 were $4.1 million (9% of revenue) and $4.7 million (8% of revenue)~~2024, ~~respectively.~~compared ~~Production~~to ~~taxes~~same ~~for~~periods ~~the fourth quarters~~ of 2023, ~~and~~is ~~2022~~primarily ~~were~~due ~~$0.9~~to ~~million~~a ~~(8%~~reduction of ~~revenue)~~the ~~and~~Partnership’s estimated ~~$1.5~~proved ~~million~~developed ~~(9%~~resulting offrom ~~revenue),~~well ~~respectively.~~performance ~~Oil~~during ~~production~~2024 ~~comprised~~during ~~approximately 61% and 63%, respectively, of~~ the Partnership’s ~~sold~~June ~~production~~30, ~~volumes~~2024 inand ~~the years ended~~ December 31, ~~2023~~2024 reserve ~~and 2022, respectively~~analyses.

~~General and administrative expenses~~40

General and administrative costs for the years ended December 31, 2023 and 2022 were $2.3 million and $2.4 million, respectively. The principal components of general and administrative expense are accounting, legal, advisory, consulting and management fees.Index

43Interest income (expense), net

~~Index~~Interest expense, net for the year ended December 31, 2024 was approximately $259,000. Interest income, net for the year ended December 31, 2023 was approximately $257,000. The primary component of interest expense in 2024 was interest expense on the BancFirst Credit Facility (“Credit Facility”).

~~Depreciation,~~Supplemental ~~depletion,~~Non-GAAP ~~amortization and accretion (“DD&A”)~~Measure

~~DD&A~~The ofPartnership ~~capitalized~~uses ~~drilling~~“Adjusted ~~and~~EBITDAX”, defined ~~development~~as ~~costs~~earnings of(loss) ~~producing~~before ~~oil~~(i) interest (income) expense, ~~natural~~net; ~~gas~~(ii) income taxes; (iii) depreciation, depletion, amortization and accretion; ~~NGL~~(iv) ~~properties~~exploration ~~are~~expenses; ~~computed~~and ~~using~~(v) (gain)/loss on the ~~unit~~mark-ofto-~~production~~market ~~method~~of onderivative instruments, as a ~~field~~key ~~basis~~supplemental ~~based~~measure of onits ~~total~~operating ~~estimated~~performance. ~~proved~~This ~~developed~~non-GAAP ~~oil~~financial measure should be considered along with, ~~natural~~but ~~gas~~not ~~and~~as ~~NGL~~alternatives ~~reserves.~~to, ~~Costs~~net ofincome, operating ~~acquiring~~income, ~~proved~~cash ~~properties~~flow ~~are~~from ~~depleted~~operating ~~using~~activities ~~the~~or ~~unit-~~other measures of~~-production~~ ~~method~~financial onperformance apresented ~~field~~in ~~basis~~accordance ~~based~~with onGAAP. ~~total~~Adjusted EBITDAX ~~estimated~~is ~~proved~~not ~~developed~~necessarily ~~and~~indicative ~~undeveloped~~of ~~reserves.~~funds ~~The~~available ~~Partnership~~to fund the Company’s ~~DD&A~~cash ~~for~~needs, ~~the~~including ~~years~~its ~~ended~~ability ~~December~~to ~~31,~~make ~~2023~~cash ~~and~~distributions. Although ~~2022~~Adjusted ~~was~~EBITDAX, ~~$18.3~~as ~~million~~calculated ~~and~~by ~~$13.7~~the ~~million~~Partnership, ~~respectively,~~may ~~and~~not ~~DD&A~~be ~~per~~comparable ~~BOE~~to ofAdjusted ~~production~~EBITDAX ~~was~~as ~~$20.29~~reported ~~and~~by ~~$17.15,~~other ~~respectively.~~companies that ~~DD&A~~do ~~for~~not ~~the~~define ~~fourth~~such ~~quarters~~terms ofexactly ~~2023~~as ~~and~~the ~~2022~~Partnership ~~was~~defines ~~$4.6~~such ~~million~~terms, ~~and~~the ~~$4.8~~Partnership ~~million,~~believes ~~respectively,~~this ~~and~~supplemental ~~DD&A~~measure ~~per~~is ~~BOE~~useful to ofinvestors ~~production~~when ~~was~~comparing ~~$22.74~~the Partnership’s results between periods and ~~$18.88,~~with ~~respectively~~other energy companies.

The ~~increase~~Partnership inbelieves ~~DD&A~~that ~~expense~~the ~~per BOE~~ presentation of ~~production~~Adjusted ~~for~~EBITDAX ~~the~~is ~~three~~important ~~months~~to ~~and~~provide ~~year~~investors ~~ended~~with ~~December~~additional ~~31,~~information ~~2023,~~(i) ~~compared~~ to ~~same~~provide ~~periods~~an ofimportant ~~2022,~~supplemental isindicator ~~primarily~~of the ~~due~~operational toperformance ~~a reduction~~ of the Partnership’s ~~estimated~~business ~~proved~~without ~~developed~~regard ~~and~~to ~~undeveloped~~financing ~~reserves~~methods ~~resulting~~and ~~from~~capital ~~changes~~structure, inand ~~the~~(ii) ~~future~~to measure ~~drill~~the ~~schedule~~operational ~~and well~~ performance ~~during~~of ~~2022~~the ~~and~~Partnership’s ~~2023~~operators.

~~Interest~~The following table reconciles the Partnership’s GAAP net income to Adjusted EBITDAX for the years ended December 31, ~~net~~2024 and 2023.

Interest income, net for the years ended December 31, 2023 and 2022 was approximately $257,000 and $149,000, respectively.

	Year Ended December 31, 2024			Year Ended December 31, 2023
Net income (loss)	$	(4,756,820	)	$	3,795,017
Interest (income) expense, net		259,399			(256,726	)
Depreciation, depletion, amortization and accretion		17,823,407			18,269,818
Exploration expenses		-			-
Adjusted EBITDAX	$	13,325,986		$	21,808,109

~~Supplemental~~Liquidity ~~Non-GAAP~~and ~~Measure~~Capital Resources

The Partnership’s ~~uses~~principal ~~“Adjusted~~sources ~~EBITDAX”,~~of ~~defined~~liquidity are ascash ~~earnings~~on-hand ~~before~~and ~~(i)~~the ~~interest~~cash ~~(income)~~flow ~~expense,~~generated ~~net;~~from ~~(ii)~~the ~~income~~properties ~~taxes;~~the ~~(iii)~~Partnership ~~depreciation,~~owns. ~~depletion,~~As ~~amortization~~of ~~and~~March ~~accretion;~~15, ~~(iv)~~2025, ~~exploration~~the ~~expenses;~~Partnership ~~and~~had ~~(v)~~approximately $1.4 ~~(gain)/loss~~million onin ~~the~~cash ~~mark~~on-~~to-market~~hand. ofThe ~~derivative~~Partnership ~~instruments,~~generated asapproximately a$13.4 ~~key~~million ~~supplemental~~and ~~measure~~$27.5 ofmillion ~~its~~(after ~~operating~~current-year ~~performance.~~reclassification; see ~~This~~Note ~~non-GAAP~~2. ~~financial~~Summary ~~measure~~of ~~should~~Significant beAccounting ~~considered~~Policies ~~along~~in ~~with~~Part II, ~~but~~Item ~~not~~8 as– ~~alternatives~~Financial ~~to,~~Statements ~~net~~and ~~income,~~Supplementary ~~operating~~Data) ~~income,~~in cash flow from operating activities orfor ~~other~~the ~~measures~~year ofended ~~financial~~December ~~performance~~31, ~~presented~~2024 inand ~~accordance~~2023, ~~with GAAP~~respectively. ~~Adjusted~~In ~~EBITDAX~~May is2024, ~~not necessarily indicative of funds available to fund~~ the ~~Company’s~~Partnership ~~cash~~entered ~~needs,~~into a ~~including~~loan ~~its~~agreement ~~ability~~with toBancFirst ~~make~~that ~~cash~~provides ~~distributions.~~for ~~Although~~a ~~Adjusted~~revolving ~~EBITDAX,~~credit asfacility ~~calculated~~for by the Partnership, ~~may~~to ~~not~~use befor ~~comparable~~future todevelopment ~~Adjusted~~of ~~EBITDAX~~oil and asnatural ~~reported~~gas bywells ~~other~~on ~~companies~~its ~~that~~undrilled doacreage ~~not~~in ~~define~~North ~~such~~Dakota. ~~terms~~The ~~exactly~~initial asborrowing ~~the~~base ~~Partnership~~is ~~defines~~$10 ~~such terms~~million, and the Partnership ~~believes~~has ~~this~~an outstanding ~~supplemental~~balance ~~measure~~of isapproximately ~~useful~~$4.6 tomillion ~~investors~~at ~~when~~December ~~comparing~~31, ~~the Partnership’s results between periods and with other energy companies~~2024.

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.41

~~The following table reconciles the Partnership’s GAAP net income to Adjusted EBITDAX for the years ended December 31, 2023 and 2022.~~Index

	Year Ended December 31, 2023			Year Ended December 31, 2022
Net income	$	3,795,017		$	21,117,332
Interest income, net		(256,726	)		(148,920	)
Depreciation, depletion, amortization and accretion		18,269,818			13,720,213
Exploration expenses		-			-
Adjusted EBITDAX	$	21,808,109		$	34,688,625

The Partnership anticipates that cash on-hand, cash flow from operations availability under the 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. As discussed in Note 4. Debt in Part II, Item 8 – Financial Statements and Supplementary Data, the Partnership was not in compliance with its debt service coverage ratio as defined within the BF Loan Agreement at December 31, 2024. The Lender waived this covenant calculation for the quarter ended December 31, 2024, and the Partnership was in compliance with its other covenants at December 31, 2024. In addition, the Lender has waived the debt service coverage ratio covenant calculation for the quarter ended March 31, 2025. If the Partnership is not in compliance with its covenants in future periods, the Partnership cannot provide any assurance or guarantee that covenant compliance waivers will be granted in future periods. If the Partnership is not able to obtain waivers, either (a) the Credit Facility may not be available for the Partnership’s use or (b) an outstanding balance under the Credit Facility may become due on demand at that time.

44Future growth is dependent on the Partnership’s ability to add reserves in excess of production. The Partnership intends to seek opportunities to invest in its existing production wells via capital expenditures and/or drill new wells on existing leasehold sites when cash flow is available. The Partnership faces the challenge of natural production volume declines, so as reservoirs are depleted, oil and natural gas production from Partnership wells will decrease. Although the Partnership anticipates its cash on-hand, cash flow from operations and availability under the Credit Facility to be adequate to fund its cash requirements, if market prices for oil and natural gas decline and/or production from Partnership wells is not replenished through the completion of new well investments, 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 fund distributions to its limited partners and/or participate in future drilling programs as proposed by the operators of the Bakken Assets.

~~Index~~Partners’ Equity

~~Liquidity~~The Partnership completed its best-efforts offering of common units on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and ~~Capital~~proceeds ~~Resources~~net of offering costs of $204.3 million.

~~The~~Under ~~Partnership’s~~the ~~principal~~agreement ~~sources~~with the Dealer Manager, the Dealer Manager received a total of ~~liquidity~~6% ~~are~~in ~~cash~~selling ~~on-hand~~commissions and ~~the~~a ~~cash~~marketing ~~flow~~expense ~~generated~~allowance ~~from~~based ~~the~~on ~~properties~~gross proceeds of the ~~Partnership~~common ~~owns~~units sold. AsThe ofDealer ~~March~~Manager also 1,has ~~2024,~~Dealer ~~the~~Manager ~~Partnership~~Incentive ~~had~~Fees ~~approximately~~(defined ~~$1.5~~below) ~~million~~where inthe ~~cash~~Dealer ~~on-hand.~~Manager ~~The~~could ~~Partnership~~receive ~~generated~~distributions ~~approximately~~up ~~$27.2~~to ~~million~~an ~~and~~additional ~~$31.5~~4% ~~million~~of gross inproceeds ~~cash~~of ~~flow~~the ~~from~~common ~~operating~~units ~~activities~~sold ~~for~~in the ~~year~~Partnership’s ~~ended~~best-efforts ~~December~~offering ~~31,~~as ~~2023~~outlined ~~and~~in ~~2022,~~the ~~respectively.~~prospectus ~~The~~for ~~Partnership anticipates~~ that ~~cash~~offering based on~~-hand~~ ~~and~~the ~~cash~~performance ~~flow~~of ~~from~~the ~~operations~~Partnership. ~~will~~Based beon ~~adequate~~the tocommon ~~meet~~units ~~its~~sold ~~liquidity~~through ~~requirements~~the ~~for~~conclusion atof ~~least~~the offering, the ~~next~~Dealer 12Manager Incentive ~~months,~~Fees ~~including~~are ~~completing~~approximately ~~the~~$8.7 ~~outstanding~~million, ~~capital~~subject ~~expenditures~~to ~~discussed~~Payout (defined below).

Future growth is dependent on the Partnership’s ability to add reserves in excess of production. The Partnership intends to seek opportunities to invest in its existing production wells via capital expenditures and/or drill new wells on existing leasehold sites when cash flow is available. The Partnership faces the challenge of natural production volume declines, so as reservoirs are depleted, oil and natural gas production from Partnership wells will decrease. Although the Partnership anticipates its cash on-hand and cash flow from operations to be adequate to fund its cash requirements, if market prices for oil and natural gas decline and/or production from Partnership wells is not replenished through the completion of new well investments, 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 fund distributions to its limited partners and/or participate in future drilling programs as proposed by the operators of the Bakken Assets. Although the Partnership did extinguish its revolving credit facility in November 2019, the Partnership may utilize available financing in the future, particularly for future capital expenditures, if needed.Distributions

See the definition and discussion of “Payout” in Note 5. Capital Contribution and Partners’ Equity in Part II, Item 8 – Financial Statements and Supplementary Data.

~~The~~For ~~Partnership~~the ~~completed~~year ~~its~~ended ~~best-efforts~~December ~~offering~~31, of2024, ~~common~~the ~~units~~Partnership declared onand ~~October~~paid ~~24,~~distributions ~~2019. As~~ of ~~the~~$1.282163 ~~conclusion~~per ofcommon ~~the offering~~unit, ~~the~~or ~~Partnership~~$14.1 ~~had~~million. ~~completed~~For the ~~sale~~year ofended ~~approximately~~December ~~11.0~~31, ~~million~~2023, ~~common~~the ~~units~~Partnership declared ~~for~~and ~~total~~paid ~~gross~~distributions ~~proceeds~~ of $~~218~~2.0939163 ~~million~~per ~~and~~common ~~proceeds~~unit, ~~net~~or ~~of offering costs of~~ $~~204~~32.34 million.

~~Under~~The ~~the~~Partnership ~~agreement~~is ~~with~~permitted ~~the~~to ~~Managing~~make ~~Dealer,~~distributions ~~the~~to ~~Managing~~its ~~Dealer~~limited ~~received~~partners so along ~~total~~as ofthe 6%Partnership is in ~~selling~~compliance ~~commissions~~with ~~and~~its adebt ~~marketing~~service ~~expense~~coverage ~~allowance~~ratio ~~based~~and onno ~~gross~~other ~~proceeds~~event of default has occurred. As noted above, the ~~common~~Partnership ~~units~~was ~~sold~~not in compliance with its debt service coverage ratio at December 31, 2024. The ~~Managing~~Lender ~~Dealer~~granted ~~also~~a ~~has~~waiver ~~Dealer~~for this ~~Manager~~covenant ~~Incentive~~calculation ~~Fees~~for ~~(defined~~the ~~below)~~quarters ~~where~~ended December 31, 2024 and March 31, 2025, but the ~~Managing~~Partnership ~~Dealer~~cannot ~~could~~provide ~~receive~~any ~~distributions~~assurance or upguarantee that covenant compliance waivers will be granted in future periods. Therefore, while the Partnership’s goal is to anmaintain a ~~additional~~relatively 4%stable ofdistribution ~~gross~~rate ~~proceeds~~over the life of its program, the ~~common~~General ~~units~~Partner ~~sold~~monitors monthly Partnership distributions in conjunction with the Partnership’s ~~best-efforts~~projected ~~offering~~cash asrequirements ~~outlined~~for inoperations, payments on the ~~prospectus~~Credit Facility and capital expenditures for ~~that~~new ~~offering~~wells. ~~based~~There oncan be no assurance as to the ~~performance~~classification or duration of distributions at the ~~Partnership~~current distribution rate. ~~Based~~If ondistributions are ~~the~~not ~~common~~paid ~~units~~or ~~sold~~are ~~through~~reduced, the ~~conclusion~~difference ofto the ~~offering,~~current ~~the~~distribution ~~Dealer~~rate ~~Manager~~per ~~Incentive~~common ~~Fees~~unit ~~are~~will ~~approximately~~be ~~$8.7~~deferred ~~million,~~and ~~subject~~is required to ~~Payout~~be ~~(defined~~paid before ~~below)~~final Payout occurs.

~~Distributions~~42

~~See the definition and discussion of “Payout” in Note 4. Capital Contribution and Partners’ Equity in Part II, Item 8 – Financial Statements and Supplementary Data.~~Index

~~For~~Oil ~~the year ended December 31, 2023, the Partnership declared~~ and ~~paid~~Natural ~~distributions~~Gas ~~of $2.939163 per common unit, or $32.4 million. For the year ended December 31, 2022, the Partnership declared and paid distributions of $1.396164 per common unit, or $15.4 million.~~Properties

~~While~~Future the Partnership’s goal is to maintain a relatively stable distribution rate over the life of its program, 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 of $1.40 per common unit per year. 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, as discussed above.Investment

45The Partnership incurred approximately $2.8 million and $10.0 million, respectively, in capital expenditures for the years ended December 31, 2024 and 2023. The Partnership has 3 wells in various stages of the drilling and completion process, and the Partnership estimates its share of capital expenditures to complete those 3 wells to be less than $1 million. In addition to the estimated capital expenditures for in-process wells, the Partnership anticipates that it may be obligated to invest an additional $30 to $40 million in drilling capital expenditures from 2025 through 2029 to participate in new well development in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements or North Dakota statutes governing the Bakken Assets.

~~Index~~Since the Partnership is not the operator of any of its oil and natural gas properties, it is difficult to predict levels of future participation in the drilling and completion of new wells, the timing of such activities and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast for 2025. Current estimated capital expenditures could be significantly different from amounts actually invested.

~~Oil~~The Partnership expects to fund overhead costs and ~~Natural~~capital ~~Gas~~additions ~~Properties~~related to the drilling and completion of wells primarily from cash on hand and cash generated by operating activities. 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 and would be subject to a non-consent penalty.

~~Future~~Oil, ~~Investment~~Natural Gas and NGL Reserves

The Partnership ~~incurred~~continually ~~approximately~~updates ~~$10.0~~its ~~million~~proved undeveloped ~~and~~reserves ~~$11.7~~(“PUD”) ~~million,~~during ~~respectively,~~its insemi-annual ~~capital~~review ~~expenditures~~based ~~for~~on ~~the~~current ~~years~~market ~~ended~~conditions ~~December 31, 2023~~ and ~~2022.~~future ~~The~~capital ~~Partnership~~investment information ~~has~~provided 8by ~~wells~~operators ~~in various stages~~ of the ~~drilling~~Bakken ~~and~~Assets ~~completion~~as ~~process,~~these ~~and~~factors ~~the~~may ~~Partnership~~change ~~estimates~~the ~~its~~planned ~~share~~timing of ~~capital~~drilling ~~expenditures~~and tocompleting ~~complete~~PUD ~~those~~reserve locations 8within ~~wells~~the toSEC befive-year ~~less~~window. ~~than~~See $1Note ~~million~~8. InSupplementary ~~addition~~Information toon ~~the estimated capital expenditures for in-process wells~~Oil, ~~the~~Natural ~~Partnership~~Gas ~~anticipates~~and ~~that~~Natural itGas ~~may~~Liquid beReserves ~~obligated to invest an additional $20 to $30 million~~ (Unaudited) in ~~drilling~~Part ~~capital~~II, ~~expenditures~~Item ~~from~~8 ~~2024~~– ~~through~~Financial ~~2028~~Statements toand ~~participate~~Supplementary inData ~~new~~for ~~well~~complete ~~development~~information inon the ~~Bakken~~Partnership’s ~~Assets~~reserves ~~without~~as of ~~becoming~~December ~~subject~~31, to2024 ~~non-consent~~and ~~penalties under the joint operating agreements or North Dakota statutes governing the Bakken Assets~~2023.

~~Since~~Transactions ~~the~~with ~~Partnership~~Related is not the operator of any of its oil and natural gas properties, it is difficult to predict levels of future participation in the drilling and completion of new wells, the timing of such activities and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast for 2024. Current estimated capital expenditures could be significantly different from amounts actually invested.Parties

The Partnership ~~expects~~has, ~~to fund overhead costs~~ and ~~capital~~is ~~additions~~expected ~~related~~to continue to ~~the~~engage ~~drilling~~in, ~~and~~significant ~~completion~~transactions ofwith ~~wells~~related ~~primarily from cash on hand and cash generated by operating activities~~parties. IfThese antransactions ~~operator~~cannot ~~elects~~be construed to ~~complete~~be ~~drilling~~at orarm’s ~~other~~length ~~significant capital expenditure activity~~ and the results ~~Partnership~~of ~~is unable to fund~~ the ~~capital~~Partnership’s ~~expenditures,~~operations ~~the General Partner~~ may ~~decide~~be todifferent ~~farmout~~than ~~the well. Also,~~ if aconducted ~~well~~with isnon-related ~~proposed~~parties. ~~under~~The ~~the~~General ~~operating~~Partner’s Board ~~agreement~~of ~~for~~Directors ~~one~~oversees ofand ~~the~~reviews ~~properties~~ the Partnership’s ~~owns,~~related ~~the~~party ~~General~~relationships ~~Partner~~and ~~may~~is ~~elect~~required to ~~“non-consent”~~approve ~~the~~any ~~well.~~significant modifications ~~Non-consenting a well will generally cause the Partnership not~~ to beexisting ~~obligated~~related toparty ~~pay the costs of the well~~transactions, ~~but~~as ~~the Partnership will not be entitled to the proceeds of production from the~~ well ~~and~~as ~~would~~any benew ~~subject~~significant torelated aparty ~~non-consent penalty~~transactions.

~~Oil~~See further discussion in Note 6. Related Parties in Part II, ~~Natural~~Item ~~Gas~~8 – Financial Statements and ~~NGL~~Supplementary ~~Reserves~~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.

~~The~~Critical ~~Partnership~~Accounting ~~continually~~Policies ~~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 Bakken Assets as these factors may change the planned timing of drilling and completing PUD reserve locations within the SEC five-year window. See Note 7. 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, 2023 and 2022.Estimates

~~Transactions~~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 ~~Related~~U.S. ~~Parties~~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 ~~has,~~critical ~~and~~accounting ispolicies are ~~expected~~important to ~~continue~~the toportrayal ~~engage~~of ~~in,~~both ~~significant~~its ~~transactions~~financial ~~with~~condition ~~related~~and ~~parties.~~results ~~These~~of ~~transactions~~operations ~~cannot~~and berequire ~~construed~~the Partnership to bemake atdifficult, subjective ~~arm’s~~or ~~length~~complex ~~and~~assumptions ~~the~~or ~~results~~estimates ofabout ~~the~~matters ~~Partnership’s~~that ~~operations~~are ~~may~~uncertain. beThe ~~different~~Partnership ~~than~~would ifreport ~~conducted~~different ~~with~~amounts ~~non-related~~in ~~parties.~~its consolidated ~~The~~financial ~~General~~statements, ~~Partner’s~~which ~~Board~~could ofbe ~~Directors~~material, ~~oversees~~if ~~and reviews~~ the Partnership’s ~~related~~used ~~party~~different ~~relationships~~assumptions ~~and~~or isestimates. ~~required~~The toPartnership believes ~~approve~~that ~~any~~the ~~significant~~following ~~modifications~~are tothe ~~existing~~critical ~~related~~accounting ~~party~~policies ~~transactions,~~used asin ~~well~~the aspreparation ~~any~~of ~~new~~its ~~significant~~consolidated ~~related~~financial ~~party transactions~~statements.

See further discussion in Note 5. 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.43

~~Critical Accounting Policies and Estimates~~Index

~~The~~Oil ~~discussion~~ and ~~analysis~~Natural ofGas 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.Properties

46The 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.

~~Index~~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 ~~Partnership’s~~application ~~critical~~of the successful efforts method of accounting ~~policies~~requires ~~are~~managerial ~~important~~judgment to determine the ~~portrayal~~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 ~~its~~judgment ~~financial~~and ~~condition~~industry experience. Wells may be completed that are assumed to be productive and ~~results~~actually ofdeliver ~~operations~~oil, natural gas and ~~require~~natural ~~the~~gas ~~Partnership~~liquids in quantities insufficient to ~~make~~be ~~difficult~~economic, ~~subjective~~which ormay ~~complex~~result ~~assumptions~~in orthe ~~estimates~~abandonment ~~about~~of ~~matters~~the wells at a later date. Wells are drilled that have targeted geologic structures that are ~~uncertain~~both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. ~~The~~Delineation seismic ~~Partnership~~incurred ~~would~~to ~~report~~select ~~different~~development ~~amounts~~locations inwithin ~~its~~an ~~consolidated~~oil ~~financial~~and ~~statements,~~natural ~~which~~gas ~~could~~field beis ~~material~~typically considered a development cost and capitalized, but ifoften these seismic programs extend beyond the ~~Partnership~~reserve ~~used~~area ~~different~~considered ~~assumptions~~proved orand ~~estimates~~management must estimate the portion of the seismic costs to expense. The ~~Partnership~~evaluation ~~believes~~of ~~that~~oil ~~the~~and ~~following~~natural ~~are~~gas ~~the~~leasehold ~~critical~~acquisition ~~accounting~~costs ~~policies~~requires ~~used~~managerial injudgment to estimate the ~~preparation~~fair value of ~~its~~these ~~consolidated~~costs ~~financial~~with ~~statements~~reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

~~Oil~~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~~natural ~~Gas~~gas ~~Properties~~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.

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.Impairment

NoThe ~~gains~~Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or ~~losses~~circumstances ~~are~~indicate ~~recognized~~that ~~upon~~the recorded carrying value of the ~~disposition~~properties may not be recoverable. Such events include a projection of ~~proved~~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 ~~properties~~liquids ~~except~~and infuture ~~transactions~~inflation ~~such~~levels. asIf the ~~significant~~carrying ~~disposition~~amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an ~~amortizable~~impairment ~~base~~expense ~~that~~equal to ~~significantly~~the ~~affects~~difference between the ~~unit–~~carrying value and the fair value of~~–production~~ ~~amortization~~the ~~rate~~properties, which is estimated to be the expected present value of the future net cash flows. ~~Sales~~Estimated ~~proceeds~~future net cash flows are ~~credited~~based toon 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 ~~carrying~~impairment ~~value~~evaluation. The underlying commodity prices used in the determination of the ~~properties~~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.

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.44

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.Index

~~Impairment~~Estimates of Oil, Natural Gas and Natural Gas Liquids Reserves

The Partnership’s ~~assesses~~estimates ~~its~~of 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 are ~~that~~based ~~will~~on ~~be produced from a field,~~ the ~~timing~~quantities of ~~this future production, future costs to produce the~~ oil, natural gas and natural gas liquids ~~and~~which, ~~future~~by ~~inflation~~analysis ~~levels. If the carrying amount~~ of ~~the~~geoscience ~~properties~~and ~~exceeds~~engineering ~~the~~data, ~~sum~~can ~~of the~~ be estimated ~~undiscounted~~with ~~future~~reasonable ~~net~~certainty ~~cash~~to ~~flows,~~be ~~the~~economically ~~Partnership~~producible ~~recognizes~~– anfrom ~~impairment~~a ~~expense~~given ~~equal~~date toforward, ~~the~~from ~~difference~~known ~~between~~reservoirs, ~~the carrying value~~ and ~~the~~under existing ~~fair~~economic ~~value~~conditions, ofoperating ~~the properties~~methods, ~~which~~and isgovernment ~~estimated~~regulations to– beprior ~~the~~to ~~expected present value of~~ the ~~future~~time ~~net~~at ~~cash~~which ~~flows.~~contracts ~~Estimated~~providing ~~future~~the right ~~net~~to ~~cash~~operate ~~flows are based on existing reserves~~expire, ~~forecasted~~unless ~~production~~evidence ~~and~~indicates ~~cost~~that ~~information~~renewal ~~and~~is ~~management’s~~reasonably ~~outlook of future commodity prices. Where probable and possible reserves exist~~certain, anregardless ~~appropriately~~of ~~risk~~whether ~~adjusted~~deterministic ~~amount~~or ofprobabilistic methods ~~these~~are ~~reserves~~used isfor ~~included in~~ the ~~impairment evaluation~~estimate. ~~The~~Reserves ~~underlying~~for ~~commodity~~proved ~~prices~~developed ~~used~~producing inwells ~~the~~were ~~determination of the Partnership’s~~ estimated ~~future~~using ~~net~~production ~~cash~~performance ~~flows~~and ~~are~~material balance ~~based~~methods. onCertain ~~NYMEX~~new ~~forward~~producing ~~strip~~properties ~~prices~~with atlittle ~~the~~production ~~end~~history ofwere ~~the~~forecast ~~period,~~using ~~adjusted~~a bycombination ~~field~~of orproduction ~~area~~performance and ~~for~~analogy ~~estimated~~to ~~location~~offset ~~and quality differentials~~production, asboth ~~well~~of aswhich ~~other~~provide ~~trends~~accurate ~~and factors that management believes will impact realizable prices~~forecasts. ~~Future~~Non–producing ~~operating~~reserve ~~costs~~ estimates ~~are~~for ~~also~~both developed ~~based~~and undeveloped onproperties awere ~~review~~forecast ofusing ~~actual~~either ~~costs~~volumetric ~~by field~~ and/or ~~area~~analogy methods. ~~Downward~~These ~~revisions~~methods inprovide ~~estimates~~accurate offorecasts ~~reserve~~due ~~quantities~~to orthe mature ~~expectations~~nature of ~~falling~~the ~~commodity~~properties ~~prices~~targeted orfor ~~rising~~development ~~operating costs could result in a reduction in undiscounted future cash flows~~ and ~~could~~an ~~indicate~~abundance aof ~~property~~subsurface ~~impairment~~control data.

47The 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.

~~Index~~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.

~~Estimates~~Revenue ~~of Oil, Natural Gas and Natural Gas Liquids Reserves~~Recognition

The Partnership’s ~~estimates~~is ofbound ~~proved~~by ~~reserves~~a ~~are~~joint ~~based~~operating onagreement with the ~~quantities~~operator of ~~oil,~~each ~~natural~~of ~~gas~~its ~~and~~producing ~~natural~~wells. ~~gas~~Under ~~liquids~~the ~~which~~joint operating agreement, bythe ~~analysis~~Partnership’s proportionate share of production ~~geoscience~~is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and ~~engineering~~records ~~data,~~the ~~can~~related berevenue ~~estimated~~in ~~with~~the ~~reasonable~~month ~~certainty~~production is delivered to bethe ~~economically~~purchaser. ~~producible~~As –the ~~from~~Partnership adoes not ~~given~~operate ~~date~~its ~~forward~~properties, ~~from~~it ~~known~~receives ~~reservoirs~~actual oil, natural gas, and ~~under~~NGL ~~existing~~sales ~~economic~~volumes ~~conditions~~and prices, ~~operating~~net ~~methods,~~of ~~and~~costs ~~government~~incurred ~~regulations~~by –the ~~prior~~operators, two to three months after the ~~time~~date atproduction ~~which~~is ~~contracts~~delivered ~~providing~~by the ~~right~~operator. toAt ~~operate~~the ~~expire,~~end ~~unless~~of ~~evidence~~each ~~indicates~~month ~~that~~when ~~renewal~~the isperformance ~~reasonably~~obligation ~~certain~~is satisfied, ~~regardless~~the ofvariable ~~whether~~consideration ~~deterministic~~can orbe ~~probabilistic~~reasonably ~~methods~~estimated ~~are~~and ~~used~~amounts ~~for~~due from the ~~estimate.~~Partnership’s ~~Reserves~~operators ~~for~~are ~~proved~~accrued ~~developed~~in Accounts ~~producing~~receivable ~~wells~~and ~~were~~other ~~estimated~~current ~~using~~assets ~~production~~in ~~performance~~the ~~and~~consolidated ~~material~~ balance ~~methods~~sheets. ~~Certain~~Variances ~~new~~between ~~producing~~the ~~properties~~Partnership’s ~~with~~estimated ~~little~~revenue and ~~production~~actual ~~history~~payments ~~were~~are ~~forecast~~recorded ~~using~~in athe ~~combination~~month ofthe ~~production~~payment ~~performance~~is received; differences have been and ~~analogy~~are toinsignificant. ~~offset~~As ~~production~~a result, ~~both~~the ofvariable consideration ~~which~~is ~~provide~~not ~~accurate forecasts~~constrained. ~~Non–producing~~The ~~reserve~~Partnership ~~estimates~~has ~~for~~elected ~~both~~to ~~developed~~utilize ~~and~~the ~~undeveloped~~practical ~~properties~~expedient ~~were~~in ~~forecast~~ASC ~~using~~606 ~~either~~that ~~volumetric~~states ~~and/or~~the ~~analogy~~Partnership is ~~methods.~~not ~~These~~required ~~methods~~to ~~provide~~disclose ~~accurate~~the ~~forecasts~~transaction ~~due~~price allocated to remaining performance obligations if the ~~mature~~variable ~~nature~~consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of ~~the~~product ~~properties~~represents ~~targeted~~a ~~for~~separate ~~development~~performance ~~and~~obligation; antherefore, future ~~abundance~~volumes are wholly unsatisfied, and disclosure of ~~subsurface~~the ~~control~~transaction ~~data~~price allocated to remaining performance obligations is not required.

~~The~~Virtually ~~accuracy~~all of ~~any reserve estimate is a function of~~ the ~~quality of available data, engineering and geological interpretation and judgment. For example, the~~ Partnership’s ~~must~~contracts’ pricing ~~estimate~~provisions ~~the~~are ~~amount~~tied ~~and~~to ~~timing~~a ofmarket ~~future operating costs~~index, ~~severance~~with ~~taxes,~~certain ~~development~~adjustments ~~costs~~based ~~and workover costs~~on, ~~all~~among ofother ~~which may vary considerably from actual results. In addition~~factors, aswhether ~~prices~~a ~~and~~well ~~cost~~delivers ~~levels~~to ~~change~~a ~~from~~gathering or ~~year~~transmission ~~to year~~line, ~~the~~quality ~~estimate~~ of ~~proved~~oil, ~~reserves~~natural ~~also~~gas ~~changes.~~and ~~Any~~natural ~~significant~~gas ~~variance~~liquids inand ~~these~~prevailing ~~assumptions~~supply ~~could materially affect the estimated quantity~~ and ~~value~~demand ofconditions, ~~the~~so ~~Partnership’s~~that ~~reserves.~~prices fluctuate ~~Independent~~to ~~reserve~~remain ~~engineers~~competitive ~~prepare~~with ~~the~~other ~~Partnership’s~~available ~~reserve estimates at the end of each year~~suppliers.

~~Despite~~Subsequent 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.Events

~~Revenue~~In ~~Recognition~~January 2025, the Partnership declared and paid $1.4 million, or $0.123285 per outstanding common unit, in distributions to its holders of common units.

~~The~~In ~~Partnership~~February ~~is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement~~2025, the Partnership’s ~~proportionate~~declared ~~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 paid ~~records the related revenue in the month production is delivered to the purchaser~~$1.1 ~~As the Partnership does not operate its properties~~million, itor ~~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~~$0.098628 Atper ~~the~~outstanding ~~end~~common ~~of each month when the performance obligation is satisfied~~unit, ~~the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued~~ in ~~Accounts~~distributions receivable and other current assets 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~~its ~~the~~holders 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~~common ~~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~~units.

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 2024, the Partnership declared and paid $1.1 million, or $0.098628 per outstanding common unit, in distributions to its holders of common units.

In February 2024, the Partnership declared and paid $1.1 million, or $0.098628 per outstanding common unit, in distributions to its holders of common units.

Item 7A. Quantitative and Qualitative Disclosure about Market Risk

~~Information~~The ~~regarding~~Partnership ~~the~~has ~~Partnership’s~~a ~~hedging~~variable ~~programs~~interest torate ~~mitigate~~on ~~commodity~~the ~~risks~~Credit Facility that is ~~contained~~subject to market changes in ~~Item~~interest 1rates. –Information ~~Business,~~regarding the Partnership’s current credit facility is contained in 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.

4845

Index

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 Resources 12, L.P.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Energy Resources 12, L.P. (the Partnership) as of December 31, ~~2023~~2024 and ~~2022~~2023, the related consolidated statements of operations, partners’ equity and cash flows for each of the two years in the period ended December 31, ~~2023~~2024, 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, ~~2023~~2024 and ~~2022~~2023, and the results of its operations and its cash flows for each of the two years in the period ended December 31, ~~2023~~2024, 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 audits 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 audits provide a reasonable basis for our opinion.

Index

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.

		Depreciation, Depletion, and Amortization of oil and natural gas properties

Description of the Matter		As of December 31, 2024, the net book value of the Partnership's oil and gas properties was $156.1 million, and depreciation, depletion and amortization (DD&A) expense was $17.9 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.

Index

		Depreciation, Depletion, and Amortization of oil and natural gas properties
Description of the Matter		As of December 31, 2023, the net book value of the Partnership's oil and gas properties was $171.1 million, and depreciation, depletion and amortization (DD&A) expense was $18.3 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 2017.

Richmond, Virginia

March 1526, ~~2024~~2025

5047

Index

Energy Resources 12, L.P.

Consolidated Balance Sheets

	December 31,			December 31,
	2023			2022
	2024			2023
Assets
Cash and cash equivalents	$	1,~~455~~463,~~619~~582		$	181,~~442~~455,~~414~~619
Accounts receivable and other current assets		43,~~472~~885,~~150~~384			94,~~360~~472,~~950~~150
Total Current Assets		5,~~927~~348,~~769~~966			275,~~803~~927,~~364~~769
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $83,340,469 and $65,100,662, respectively		171,101,264			179,376,326
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $101,131,766 and $83,340,469, respectively		156,140,235			171,101,264
Total Assets	$	177,029,033		$	207,179,690
Other assets, net		13,276			-
Total Assets	$	161,502,477		$	177,029,033
Liabilities
Accounts payable and accrued expenses	$	31,~~058~~961,~~704~~745		$	43,~~449~~058,~~340~~704
Total Current Liabilities		31,~~058~~961,~~704~~745			43,~~449~~058,~~340~~704
Asset retirement obligations		729,315			695,889
Revolving credit facility		4,600,000			-
Total Liabilities		3,788,019			5,145,229
Asset retirement obligations		765,443			729,315
Total Liabilities		7,327,188			3,788,019
Partners’ Equity
Limited partners' interest (11,031,579 common units issued and outstanding, respectively)		173,241,229			202,034,676
Limited partners’ interest (11,031,579 common units issued and outstanding, respectively)		154,175,504			173,241,229
General partner's interest		(215	)		(215	)
General partner’s interest		(215	)		(215	)
Total Partners’ Equity		~~173~~154,~~241~~175,~~014~~289			~~202~~173,~~034~~241,~~461~~014
Total Liabilities and Partners’ Equity	$	~~177~~161,~~029~~502,~~033~~477		$	~~207~~177,~~179~~029,~~690~~033

See notes to consolidated financial statements.

5148

Index

Energy Resources 12, L.P.

Consolidated Statements of Operations

	Year Ended			Year Ended
	Year Ended December 31, 2024			Year Ended December 31, 2023
	December 31, 2023			December 31, 2022
Revenues
Oil	$	4231,~~362~~223,~~325~~155		$	4742,~~366~~362,~~846~~325
Natural gas		21,~~752~~534,~~372~~285			52,~~981~~752,~~108~~372
Natural gas liquids		3,~~512~~360,~~566~~700			43,~~800~~512,~~447~~566
Total revenue		4836,~~627~~118,~~263~~140			5848,~~148~~627,~~401~~263
Operating costs and expenses
Production expenses		2017,~~398~~670,~~873~~082			1620,~~367~~398,~~549~~873
Production taxes		42,~~113~~923,~~774~~118			4,~~698~~113,~~786~~774
General and administrative expenses		2,~~306~~198,~~507~~954			2,~~393~~306,~~441~~507
Depreciation, depletion, amortization and accretion		1817,~~269~~823,~~818~~407			1318,~~720~~269,~~213~~818
Total operating costs and expenses		4540,~~088~~615,~~972~~561			3745,~~179~~088,~~989~~972
Operating income		3,538,291			20,968,412
Operating income (loss)		(4,497,421	)		3,538,291
Interest income, net		256,726			148,920
Interest income (expense), net		(259,399	)		256,726
Total other income (expense), net		~~256~~(259,~~726~~399	)		~~148~~256,~~920~~726
Net income	$	3,795,017		$	21,117,332
Net income (loss)	$	(4,756,820	)	$	3,795,017
Basic and diluted net income per common unit	$	0.34		$	1.91
Basic and diluted net income (loss) per common unit	$	(0.43	)	$	0.34
Weighted average common units outstanding - basic and diluted		11,031,579			11,031,579

See notes to consolidated financial statements.

5249

Index

Energy Resources 12, L.P.

Consolidated Statements of Partners’ Equity

	Limited Partner					General ~~Partner~~			Total ~~Partners'~~
	Common Units		Amount			Partner Amount			Partners’ Equity
Balances - December 31, 2021		11,031,579	$	196,798,238		$	(215	)	$	196,798,023
Balances - December 31, 2022		11,031,579	$	202,034,676		$	(215	)	$	202,034,461
Distributions declared and paid to common units ($1.396164 per common unit)		-		(15,401,894	)		-			(15,401,894	)
Estimated state tax withholding for limited partners		-		(479,000	)		-			(479,000	)
Net income		-		21,117,332			-			21,117,332
Balances - December 31, 2022		11,031,579		202,034,676			(215	)		202,034,461
Distributions declared and paid to common units ($2.939163 per common unit)		-		(32,423,609	)		-			(32,423,609	)
Adjustment to state tax withholding for limited partners		-		145			-			145
State tax withholding payments made on behalf of limited partners		-		(364,855	)		-			(364,855	)
Estimated state tax withholding for limited partners		-		(165,000	)		-			(165,000	)
Reversal of estimated state tax withholding for limited partners		-		365,000			-			365,000
Estimated state tax withholding for limited partners for tax year 2023		-		(165,000	)		-			(165,000	)
Net income		-		3,795,017			-			3,795,017
Balances - December 31, 2023		11,031,579	$	173,241,229		$	(215	)	$	173,241,014
Distributions declared and paid to common units ($1.282163 per common unit)		-		(14,144,282	)		-			(14,144,282	)
State tax withholding payments made on behalf of limited partners		-		(673,623	)		-			(673,623	)
Reversal of estimated state tax withholding for limited partners		-		644,000			-			644,000
Estimated state tax withholding for limited partners for tax year 2024		-		(135,000	)		-			(135,000	)
Net loss		-		(4,756,820	)		-			(4,756,820	)
Balances - December 31, 2024		11,031,579	$	154,175,504		$	(215	)	$	154,175,289

See notes to consolidated financial statements.

5350

Index

Energy Resources 12, L.P.

Consolidated Statements of Cash Flows

	Year Ended			Year Ended
	Year Ended December 31, 2024			Year Ended December 31, 2023
	December 31, 2023			December 31, 2022
Cash flow from operating activities:
Net income	$	3,795,017		$	21,117,332
Net income (loss)	$	(4,756,820	)	$	3,795,017
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion		1817,~~269~~823,~~818~~407			1318,~~720~~269,~~213~~818
Changes in operating assets and liabilities:
Accounts receivable and other current assets		4719,~~888,800~~529			(34,~~253~~888,~~547~~800	)
Accounts payable and accrued expenses		~~217~~(389,~~951~~282	)		~~(102~~582,~~461~~806	)
Net cash flow provided by operating activities		2713,~~171~~396,~~586~~834			3127,~~481~~536,~~537~~441
Cash flow from investing activities:
Additions to oil and natural gas properties		(113,~~734~~024,~~772~~926	)		(1011,~~695~~734,~~466~~772	)
Net cash flow used in investing activities		(113,~~734~~024,~~772~~926	)		(1011,~~695~~734,~~466~~772	)
Cash flow from financing activities:
Distributions paid to limited partners		(32,423,609	)		(15,401,894	)
Cash paid for loan costs		(146,040	)		-
Net cash flow used in financing activities		(32,423,609	)		(15,401,894	)
Proceeds from revolving credit facility		4,600,000			-
Increase in cash and cash equivalents		(16,986,795	)		5,384,177
Payments for state withholding taxes on behalf of limited partners		(673,623	)		(364,855	)
Cash and cash equivalents, beginning of period		18,442,414			13,058,237
Distributions paid to limited partners		(14,144,282	)		(32,423,609	)
Cash and cash equivalents, end of period	$	1,455,619		$	18,442,414
Net cash flow used in financing activities		(10,363,945	)		(32,788,464	)
Increase in cash and cash equivalents		7,963			(16,986,795	)
Cash and cash equivalents, beginning of period		1,455,619			18,442,414
Cash and cash equivalents, end of period	$	1,463,582		$	1,455,619
Interest paid	$	177,536		$	-
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$	~~428~~229,~~483~~806		$	2428,~~201,924~~483

See notes to consolidated financial statements.

5451

Index

Energy Resources 12, L.P.

Notes to Consolidated Financial Statements

December 31, ~~2023~~2024

Note 1. Partnership Organization

Energy Resources 12, 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 December 30, 2016. The Partnership completed its best-efforts offering in October 2019 with a total of approximately 11.0 million common units sold for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

As of December 31, ~~2023~~2024, the Partnership owned an approximate 5.64% non-operated working interest in ~~422~~447 producing wells, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”)~~. The Partnership also owns an estimated approximate 5.5% non-operated working interest in 8 wells in various stages of the drilling and completion process~~, and possible future development locations in the Bakken Assets. The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 12 third-party operators on behalf of the Partnership and other working interest owners.

The general partner of the Partnership is Energy Resources 12 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 financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”).

Segment Information

The Partnership has identified only one reportable business segment, which as a non-operated interest owner of the Bakken Assets, is the production and sale of oil, natural gas and NGLs. All of the Partnership’s operations and assets are located in North Dakota, and substantially all of its revenues are attributable to United States customers.

The operating results of the Partnership’s single reportable segment are evaluated by the General Partner’s Chief Executive Officer, who has been determined to be the Partnership’s Chief Operating Decision Maker (“CODM”), to make key operating decisions, such as the allocation of resources and the evaluation of operating segment performance. The primary measure of profit and loss evaluated by the Partnership’s CODM for its single reportable segment is net income. Net income, total assets and all significant segment expense items are presented in the Partnership’s consolidated financial statements and notes to the consolidated financial statements.

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.

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, 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.

Index

Property and Depreciation, Depletion and Amortization

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.

Index

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 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, including appropriate escalators, 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.

Index

Use of Estimates

The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated 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.

Index

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 Accounts receivable and other current assets 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.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Partnership’s accounts receivable are due from the operators of the Partnership’s oil and natural gas properties in North Dakota (the 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, ~~2023~~2024 and ~~2022~~2023, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible and the Partnership’s operators do not have a history of non-payment. For the years ended December 31, ~~2023~~2024 and ~~2022~~2023, approximately 9493% and 9194% of the Partnership’s total revenue was generated through sales by four of its 12 operators, respectively. 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.

Index

Accounting for Asset Retirement Obligations

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.

57The following table shows the activity for the years ended December 31, 2024 and 2023 relating to the Partnership’s asset retirement obligations:

Index

Balance as of December 31, 2022	$	695,889
Well additions		3,415
Accretion		30,011
Revisions		-
Balance as of December 31, 2023		729,315
Well additions		4,018
Accretion		32,110
Revisions		-
Balance as of December 31, 2024	$	765,443

The following table shows the activity for the years ended December 31, 2023 and 2022 relating to the Partnership’s asset retirement obligations:

Balance as of December 31, 2021	$	743,583
Well additions		26,748
Accretion		16,958
Revisions		(91,400	)
Balance as of December 31, 2022	$	695,889
Well additions		3,415
Accretion		30,011
Revisions		-
Balance as of December 31, 2023	$	729,315

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. ~~The~~In ~~Partnership~~accordance ~~reached~~with its asettlements ~~resolution~~ with the state of North Dakota, ~~that entailed~~ the Partnership ~~making~~has amade ~~payment~~payments of ~~taxes~~(i) onapproximately ~~behalf~~$365,000 (approximately of$0.033 per common ~~certain~~unit) ~~non-resident~~in ~~limited~~May ~~partners~~2023 ~~to the state~~ for ~~the~~ tax ~~years~~year of 2021; ~~and~~(ii) ~~2022. The Partnership made a payment of~~ approximately $~~365~~532,000 (approximately $0.03 048 per common unit) in ~~May~~April ~~2023~~2024 for ~~that settled the 2021~~ tax year. ~~The~~2022; ~~Partnership~~and ~~recorded~~(iii) anapproximately ~~estimate~~$142,000 (approximately at$0.013 per ~~December~~common ~~31,~~unit) ~~2022~~in ofApril ~~approximately~~2024 ~~$479,000~~ for ~~the 2022~~ tax year. 2023. In addition, the Partnership recorded an ~~estimated~~estimate at December 31, ~~2023~~2024 of approximately $~~165~~135,000 for the ~~2023~~2024 tax year. ~~Settlements for the 2022 and 2023 tax year are expected during 2024.~~ 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 t

Filing Compare · ENERGY RESOURCES 12, L.P.