10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2020

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

Commission File Number 000-55615

Energy 11, L.P.

(Exact name of registrant as specified in its charter)

Delaware	46-3070515
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
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 Act:

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

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, a 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

As of November 5, 2020, the Partnership had 18,973,474 common units outstanding. 

Energy 11, L.P.

Form 10-Q

Index

			Page Number
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements (Unaudited)
		Consolidated Balance Sheets – September 30, 2020 and December 31, 2019	3
		Consolidated Statements of Operations – Three and nine months ended September 30, 2020 and 2019	4
		Consolidated Statements of Partners’ Equity – Three and nine months ended September 30, 2020 and 2019	5
		Consolidated Statements of Cash Flows – Nine months ended September 30, 2020 and 2019	6
		Notes to Consolidated Financial Statements	7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
	Item 4.	Controls and Procedures	28
PART II. OTHER INFORMATION
	Item 1.	Legal Proceedings	29
	Item 1A.	Risk Factors	29
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
	Item 3.	Defaults upon Senior Securities	30
	Item 4.	Mine Safety Disclosures	30
	Item 5.	Other Information	31
	Item 6.	Exhibits	31
Signatures			32

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Energy 11, L.P.

Consolidated Balance Sheets

	September 30,			December 31,
	2020			2019
	(unaudited)
Assets
Cash and cash equivalents	$	5,254,981		$	348,550
Restricted cash and cash equivalents		1,288,884			-
Oil, natural gas and natural gas liquids revenue receivable		4,714,775			5,857,926
Other current assets		418,001			284,652
Total Current Assets		11,676,641			6,491,128
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $69,699,954 and $53,186,165, respectively		328,844,767			326,758,636
Total Assets	$	340,521,408		$	333,249,764
Liabilities
Accounts payable, accrued expenses and other current liabilities	$	3,208,326		$	20,061,059
Revolving credit facility		40,000,000			-
Affiliate term loan		15,000,000			-
Total Current Liabilities		58,208,326			20,061,059
Revolving credit facility		-			24,000,000
Asset retirement obligations		1,549,927			1,452,734
Total Liabilities		59,758,253			45,513,793
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)		280,764,882			287,737,698
General partner's interest		(1,727	)		(1,727	)
Class B Units (62,500 units issued and outstanding, respectively)		-			-
Total Partners’ Equity		280,763,155			287,735,971
Total Liabilities and Partners’ Equity	$	340,521,408		$	333,249,764

See notes to consolidated financial statements.

3

Energy 11, L.P.

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended			Three Months Ended			Nine Months Ended			Nine Months Ended
	September 30, 2020			September 30, 2019			September 30, 2020			September 30, 2019
Revenues
Oil	$	8,187,180		$	6,649,652		$	22,412,183		$	22,612,030
Natural gas		636,971			429,347			1,392,651			2,066,813
Natural gas liquids		826,117			260,110			1,701,486			2,069,270
Total revenue		9,650,268			7,339,109			25,506,320			26,748,113
Operating costs and expenses
Production expenses		2,825,472			2,228,933			6,997,839			7,977,046
Production taxes		777,012			558,288			2,185,903			2,132,056
General and administrative expenses		379,569			281,308			1,300,003			1,043,293
Depreciation, depletion, amortization and accretion		6,112,621			2,767,479			16,575,336			9,403,364
Total operating costs and expenses		10,094,674			5,836,008			27,059,081			20,555,759
Operating income (loss)		(444,406	)		1,503,101			(1,552,761	)		6,192,354
Gain on derivatives		94,299			498,790			535,189			498,790
Interest expense, net		(529,789	)		(207,847	)		(1,370,418	)		(598,063	)
Total other expense, net		(435,490	)		290,943			(835,229	)		(99,273	)
Net income (loss)	$	(879,896	)	$	1,794,044		$	(2,387,990	)	$	6,093,081
Basic and diluted net income (loss) per common unit	$	(0.05	)	$	0.09		$	(0.13	)	$	0.32
Weighted average common units outstanding - basic and diluted		18,973,474			18,973,474			18,973,474			18,973,474

See notes to consolidated financial statements.

4

Energy 11, L.P.

Consolidated Statements of Partners’ Equity

(Unaudited)

	Limited Partner					Class B				General Partner			Total Partners'
	Common Units		Amount			Units		Amount		Amount			Equity
Balances - December 31, 2018		18,973,474	$	305,747,329			62,500	$	-	$	(1,727	)	$	305,745,602
Distributions declared and paid to common units ($0.349041 per common unit)		-		(6,622,520	)		-		-		-			(6,622,520	)
Net income - three months ended March 31, 2019		-		2,339,974			-		-		-			2,339,974
Balances - March 31, 2019		18,973,474		301,464,783			62,500		-		(1,727	)		301,463,056
Distributions declared and paid to common units ($0.369041 per common unit)		-		(6,622,521	)		-		-		-			(6,622,521	)
Net income - three months ended June 30, 2019		-		1,959,063			-		-		-			1,959,063
Balances - June 30, 2019		18,973,474		296,801,325			62,500		-		(1,727	)		296,799,598
Distributions declared and paid to common units ($0.349041 per common unit)		-		(6,622,520	)		-		-		-			(6,622,520	)
Net income - three months ended September 30, 2019		-		1,794,044			-		-		-			1,794,044
Balances - September 30, 2019		18,973,474	$	291,972,849			62,500	$	-	$	(1,727	)	$	291,971,122
Balances - December 31, 2019		18,973,474	$	287,737,698			62,500	$	-	$	(1,727	)	$	287,735,971
Distributions declared and paid to common units ($0.241644 per common unit)		-		(4,584,826	)		-		-		-			(4,584,826	)
Net income - three months ended March 31, 2020		-		2,933,427			-		-		-			2,933,427
Balances - March 31, 2020		18,973,474		286,086,299			62,500		-		(1,727	)		286,084,572
Net loss - three months ended June 30, 2020		-		(4,441,521	)		-		-		-			(4,441,521	)
Balances - June 30, 2020		18,973,474		281,644,778			62,500		-		(1,727	)		281,643,051
Net loss - three months ended September 30, 2020		-		(879,896	)		-		-		-			(879,896	)
Balances - September 30, 2020		18,973,474	$	280,764,882			62,500	$	-	$	(1,727	)	$	280,763,155

See notes to consolidated financial statements.

5

Energy 11, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended			Nine Months Ended
	September 30, 2020			September 30, 2019
Cash flow from operating activities:
Net income (loss)	$	(2,387,990	)	$	6,093,081
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion		16,575,336			9,403,364
Gain on mark-to-market of derivatives		(250,149	)		(498,790	)
Non-cash expenses, net		67,232			37,328
Changes in operating assets and liabilities:
Oil, natural gas and natural gas liquids revenue receivable		1,143,151			2,412,723
Other current assets		(134,283	)		(36,170	)
Accounts payable, accrued expenses and other current liabilities		39,550			(603,796	)
Net cash flow provided by operating activities		15,052,847			16,807,740
Cash flow from investing activities:
Additions to oil and natural gas properties		(35,272,706	)		(3,540,372	)
Net cash flow used in investing activities		(35,272,706	)		(3,540,372	)
Cash flow from financing activities:
Proceeds from revolving credit facility		16,000,000			3,000,000
Proceeds from affiliate term loan		15,000,000			-
Distributions paid to limited partners		(4,584,826	)		(19,867,561	)
Net cash flow provided by (used in) financing activities		26,415,174			(16,867,561	)
Increase (decrease) in cash, cash equivalents and restricted cash		6,195,315			(3,600,193	)
Cash, cash equivalents and restricted cash, beginning of period		348,550			3,685,327
Cash, cash equivalents and restricted cash, end of period	$	6,543,865		$	85,134
Interest paid	$	1,336,840		$	574,334
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$	1,714,900		$	4,366,105

See notes to consolidated financial statements.

6

Energy 11, L.P.

Notes to Consolidated Financial Statements

September 30, 2020

(Unaudited)

Note 1. Partnership Organization

Energy 11, L.P. (the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership completed its best-efforts offering on April 24, 2017 with a total of approximately 19.0 million common units sold for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.

As of September 30, 2020, the Partnership owned an approximate 25% non-operated working interest in 243 producing wells, an estimated approximate 18% non-operated working interest in 21 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL) and Oasis Petroleum North America, LLC (“Oasis”) (NYSE: OAS), two of the largest producers in the basin, operate substantially all of the Sanish Field Assets.

The general partner of the Partnership is Energy 11 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership.

The Partnership’s fiscal year ends on December 31.

Drilling Program, Oil Demand, Current Pricing, Liquidity and Going Concern Considerations

During 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling and completion of 43 new wells in the Sanish field. The Partnership estimates the total investment for these 43 new wells to be approximately $63 million. In conjunction with this drilling program performed primarily by Whiting, the Partnership had incurred approximately $42 million in capital expenditures through September 30, 2020, which was primarily funded by availability under the Partnership’s $40 million revolving credit facility (“Credit Facility”, described in Note 4. Debt). However, the Partnership used all availability under its Credit Facility by March 31, 2020, and as of June 30, 2020, the Partnership had approximately $20 million in accrued operating and capital expenditures due to Whiting. New production from completed wells was expected to enhance the Partnership’s operating performance throughout 2020, providing incremental cash flow from operations to fund the Partnership’s investment in its undrilled acreage.

Subsequent to the Partnership’s election to participate in Whiting’s drilling program, the outbreak of a novel coronavirus (“COVID-19”) in China spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries for an undetermined period of time, creating extreme volatility in capital markets and the global economy. Because of COVID-19’s impact to the global economy, demand for oil, natural gas and other hydrocarbons substantially declined in March 2020 and has remained depressed through the third quarter of 2020. Demand for oil and natural gas is not anticipated to return to pre-COVID-19 levels during 2020, and the outlook for demand for oil and natural gas in 2021 is uncertain. This reduction in demand compounded an existing excess in supply of oil and natural gas, as the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia could not agree on daily production output of crude oil in March 2020. As a result, Russia announced its intention to increase production, and Saudi Arabia immediately countered with announced reductions to export prices. All of these factors led to oil prices falling in March 2020 and to 20-year lows in April 2020. Although NYMEX oil prices have stabilized around $40 per barrel since June 2020, prices throughout the third quarter of 2020 remained below pre-COVID-19 levels.

In response to lower commodity prices and reduced demand, operators within the United States altered drilling programs and the related forecasted capital expenditures for those programs, and implemented other cost-saving measures, such as curtailing production or shutting in producing wells, during the second quarter of 2020. While operators have since returned significant inventory of existing wells to production, the nature and timing of drilling new wells remains uncertain. These factors have had and are anticipated to continue to have an adverse impact on the Partnership’s business and its financial condition. Due to the impacts to the global oil and gas industry described above, the General Partner approved the suspension of distributions to limited partners of the Partnership in March 2020. Further, Whiting and certain of its subsidiaries declared bankruptcy under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas on April 1, 2020. Subsequent to filing for Chapter 11 protection, Whiting suspended its Sanish field drilling program during the second quarter of 2020, but operated its business in the normal course without material disruption to its vendors, partners or employees, including the Partnership, during the bankruptcy process. Whiting completed its financial restructuring and emerged from bankruptcy protection in September 2020, but has yet to resume its drilling program.

7

In July 2020, the Partnership entered into a loan agreement for a one year, $15 million term loan (“Affiliate Loan”) that matures on July 21, 2021 (see Note 4. Debt for additional information). The Partnership used proceeds from the Affiliate Loan plus cash on hand to pay the Partnership’s accrued operating and capital expenditures due to Whiting, which totaled approximately $19 million at the time of payment. In addition to the Affiliate Loan, the Partnership entered into a letter agreement (“Letter Agreement”) with its lending group for its Credit Facility. The Letter Agreement, among other items, waived the non-compliance of certain covenants under the Credit Facility; however, the Letter Agreement changed the maturity date of the Credit Facility from September 30, 2022 to July 31, 2021. In October 2020, the Partnership made a principal payment on the Affiliate Loan of $5 million; therefore, the Partnership’s outstanding debt obligations at the date of filing of this Form 10-Q total $50 million and mature within one year of the filing of this Form 10-Q.

The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) the Partnership’s ability to comply with its obligations under its loan agreements (see Note 4. Debt for further discussion); (ii) refinancing its existing debt and/or securing additional capital; (iii) an increase in demand for oil and natural gas as the global economy recovers from the effects of the COVID-19 pandemic and the existing oversupply of oil in the United States; and (iv) an increase in oil and natural gas market prices, which will improve the Partnership’s cash flow generated from operations. The Partnership can provide no assurance that it will be able to achieve any of these objectives. Refinancing its existing debt or securing additional capital may not be available on favorable terms to the Partnership, if it is available at all. There also can be no assurance that economic activity and oil and natural gas market conditions, including commodity prices, will return to pre-COVID-19 levels, or that the Partnership will be able to meet its operational obligations. If the Partnership is unable to refinance or repay its debt obligations or is unable to meet its operational obligations, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy these obligations, which create the substantial doubt that exists about the ability of the Partnership to continue as a going concern for one year after the date these financial statements are issued.

The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Partnership to continue as a going concern.

Note 2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements included in its 2019 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2020 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2020.

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.

Revenue Recognition

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

8

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.

Net Income (Loss) Per Common Unit

Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (loss) per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and nine months ended September 30, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.

Recently Adopted Accounting Standards

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848), which provides optional guidance through December 31, 2022 to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments in ASU No. 2020-04 apply to contract modifications that replace a reference rate affected by reference rate reform, providing optional expedients regarding the measurement of hedge effectiveness in hedging relationships that have been modified to replace a reference rate. While the guidance in ASU No. 2020-04 became effective upon issuance, the provisions of the ASU did not have a material impact on the Partnership’s consolidated financial statements and related disclosures as of September 30, 2020.

Note 3. Oil and Natural Gas Investments

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

During 2018, six wells were completed by the Partnership’s operators. Two wells were completed by and are being operated by Whiting; the Partnership has an approximate 29% non-operated working interest in these two wells. The other four wells were completed by and are operated by Oasis; the Partnership has an approximate 8% non-operated working interest in these four wells. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million.

During 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling and completion of 43 new wells in the Sanish field. Twenty-two (22) of these 43 wells have been completed and were producing at September 30, 2020; the Partnership has an approximate non-operated working interest of 23% in these 22 wells. The Partnership has an estimated approximate non-operated working interest of 18% in the remaining 21 wells that are in-process as of September 30, 2020. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 43 wells is approximately $63 million, of which approximately $42 million was incurred as of September 30, 2020. Whiting suspended its Sanish field drilling program during the second quarter of 2020 in response to the significant reduction in demand for oil caused by COVID-19 and the oversupply of oil in the United States. The Partnership estimates it may incur approximately $1 to $2 million in additional capital expenditures during the fourth quarter of 2020; however, low commodity prices, market supply and demand imbalances and how Whiting’s emergence from bankruptcy protection in September 2020 impacts the resumption of its suspended drilling program make it difficult to predict the amount and timing of capital expenditures for the remainder of 2020. Estimated capital expenditures could be significantly different from amounts actually invested.

9

Evaluation for Potential Impairment of Oil and Natural Gas Investments

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. The Partnership considered the declines in the current and forecasted operating cash flows resulting from COVID-19 and sustained lower commodity prices to be potential indicators of impairment and, as a result, performed a test of recoverability for the Sanish Field Assets. Estimated future net cash flows calculated in the recoverability test were based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows were based on NYMEX forward strip prices as of October 1, 2020, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believed will impact realizable prices. Future operating cost estimates were based on actual historical costs of the Sanish Field Assets. The Partnership’s recoverability analyses did not identify any impairment losses as of September 30, 2020.

If current macro-economic conditions continue or worsen, the carrying value of the Partnership’s oil and natural gas properties may not be recoverable and impairment losses could be recorded in future periods.

Note 4. Debt

Revolving Credit Facility

On November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”) between and among the Partnership and Simmons Bank, as administrative agent and the lenders party thereto (the “Lender”), which provided for a revolving credit facility with an approved initial commitment amount of $20 million, subject to borrowing base restrictions. The maturity date was November 21, 2019. Effective September 30, 2019, the Partnership entered into an amendment and restatement of the Loan Agreement (the “Amended Loan Agreement”) with Lender, which provided for the Credit Facility with an approved initial commitment of $40 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The terms of the Amended Loan Agreement were generally similar to the Partnership’s existing revolving credit facility and included the following: (i) a maturity date of September 30, 2022; (ii) subject to certain exceptions, an interest rate, which did not change from the existing revolving credit facility, equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.50% to 3.50%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Amended Loan Agreement; (iii) an increase to the borrowing base from $30 million to an initially stipulated $40 million; and (iv) an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties.

At closing of the Amended Loan Agreement in October 2019, the Partnership paid an origination fee of 0.45% on the change in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000. The Partnership is also required to pay an unused facility fee of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter.

On July 21, 2020, the Partnership entered into a letter agreement (“Letter Agreement”) with Lender that amended and modified the Amended Loan Agreement. The modifications to the Amended Loan Agreement include, among other items, the following:

- Maturity date was changed from September 30, 2022 to July 31, 2021;

- Interest rate was changed to the prime rate plus 1.00%, with an interest rate floor of 4.00% (an increase of 50 basis points from the rate prior to the Letter Agreement);

- Any future Partnership distributions to limited partners require Lender approval;

- Calculation of the current ratio covenant was suspended until the reporting date of September 30, 2020;

- The definition of current ratio excludes the Affiliate Loan (discussed below) from the definition of liabilities; and

- As additional collateral for the loan, the Partnership established and funded a bank account with Lender in the amount of $1.6 million, to be used for interest payments under the Amended Loan Agreement until maturity (the balance of this collateral bank account at September 30, 2020 was approximately $1.3 million and is included in Restricted cash and cash equivalents on the Partnership’s September 30, 2020 consolidated balance sheet).

10

Also, under the Letter Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and natural gas sales. The risk management program must cover at least 80% of the Partnership’s projected total production of oil and natural gas for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021). See more information on the Partnership’s hedging program in Note 7. Risk Management.

In addition to the modification of certain terms under the Amended Loan Agreement, the Letter Agreement waived the defaults by the Partnership under the Amended Loan Agreement that existed prior to signing the Letter Agreement, including not meeting the current ratio covenant as of March 31, 2020, the Partnership not filing its first quarter financial statements within 60 days of March 31, 2020 and the non-payment by the Partnership of amounts due to Whiting. The Letter Agreement also waived the Partnership’s calculation of the current ratio covenant at June 30, 2020. The Letter Agreement also allows for the Affiliate Loan discussed below and payments under the Affiliate Loan.

In consideration for the modifications, amendments and waivers described above to the Amended Loan Agreement, the Letter Agreement provides for an amendment fee to Lender of $40,000, of which $15,000 was paid on September 30, 2020 and $25,000 is due December 31, 2020.

The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include:

● A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00

● A minimum ratio of current assets to current liabilities of 1.00 to 1.00 (“Current Ratio”)

● A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period

The Partnership was in compliance with its applicable covenants at September 30, 2020. If the Partnership is not in compliance with its covenants in future periods, it may not be able to obtain waivers and the outstanding balance under the Credit Facility may become due on demand at that time.

At September 30, 2020, the outstanding balance on the Credit Facility was $40 million, and the interest rate for the Credit Facility was 4.25%. As of September 30, 2020 and December 31, 2019, the outstanding balances on the Credit Facility were $40 million and $24 million, respectively, which approximate fair market value. The Partnership estimated the fair value of its Credit Facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

Term Loan from Affiliate

On July 21, 2020, the Partnership, as borrower, entered into a loan agreement with GKDML, LLC (“GKDML”), which provides for an unsecured, one-year term loan (“Term Loan” or “Affiliate Loan”) in the amount of $15 million. GKDML is owned and managed by Glade M. Knight and David S. McKenney, the Chief Executive Officer and the Chief Financial Officer, respectively, of the General Partner. The Term Loan bears interest at a variable rate based on LIBOR plus a margin of 2.00%, with a LIBOR floor of 0%. Interest is payable monthly. The Term Loan contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. At September 30, 2020, the outstanding balance on the Term Loan was $15 million, the interest rate for the Term Loan was approximately 2.2% and the Partnership was in compliance of all applicable covenants.

To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A. on July 21, 2020 (“GKDML Loan”). The GKDML Loan has substantially the same terms as the Term Loan and is personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and will not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimburse GKDML for all costs of the GKDML Loan. The Term Loan may be prepaid at any time with no penalty and in any amount, but any amounts repaid may not be reborrowed. 

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Note 5. Asset Retirement Obligations

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows:

	2020		2019
Balance at January 1	$	1,452,734	$	1,294,067
Well additions		35,646		73,096
Accretion		61,547		52,482
Revisions		-		-
Balance at September 30	$	1,549,927	$	1,419,645

Note 6. Fair Value of Financial Instruments

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

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

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

● Level 3: Significant unobservable inputs

The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the three and nine months ended September 30, 2020 and 2019, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2020 and December 31, 2019.

	Fair Value Measurements at September 30, 2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity derivatives - current assets	$	-	$	66,299	$	-
Total	$	-	$	66,299	$	-

	Fair Value Measurements at December 31, 2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(183,850	)	$	-
Total	$	-	$	(183,850	)	$	-

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The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheet in Other current assets at September 30, 2020 and Accounts payable, accrued expenses and other current liabilities at December 31, 2019. See additional detail in Note 7. Risk Management.

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, oil, natural gas and natural gas liquids revenue 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.

Note 7. Risk Management

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Periodically, the Partnership utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations. The Partnership settled three derivative contracts during the first quarter of 2020, and in accordance with the Letter Agreement discussed in Note 4. Debt, the Partnership is required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021). In August 2020, the Partnership established its risk management program by entering into costless collar derivative contracts for future oil and natural gas produced by the Sanish Field Assets during the period from August 2020 through February 2021. All derivative instruments are recorded on the Partnership’s balance sheet as assets or liabilities measured at fair value.

As of September 30, 2020, the Partnership’s derivative instruments with its counterparty were in a gain position; therefore, a current asset of approximately $66,000, which approximates its fair value, has been recognized as a derivative asset in Other current assets on the Partnership’s consolidated balance sheet as of September 30, 2020. As of December 31, 2019, the Partnership’s derivative instruments were in a loss position; therefore, a current liability of approximately $0.2 million, which approximates fair value, was recognized in Accounts payable, accrued expenses and other current liabilities on the Partnership’s consolidated balance sheet.

The Partnership determined the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performed an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considered that the counterparty is of substantial credit quality and had the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional discussion above in Note 6. Fair Value of Financial Instruments.

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The Partnership has not designated its derivative instruments as hedges for accounting purposes and has not entered into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents settlements of matured derivative instruments and non-cash gains on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect realized gains on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash) gains below represent the change in fair value of derivative instruments which were held at period-end.

	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Settlements on matured derivatives	$	28,000	$	-	$	285,040	$	-
Gain on mark-to-market of derivatives		66,299		498,790		250,149		498,790
Gain on derivatives	$	94,299	$	498,790	$	535,189	$	498,790

The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars, and the contracts are settled monthly. The following table reflects the open costless collar derivative instruments as of September 30, 2020.

Settlement Period	Basis	Product	Volume	Floor / Ceiling Prices ($)	Fair Value of Asset / (Liability) at September 30, 2020
10/2020 - 02/2021	NYMEX	Oil (bbls)	75,000	37.50 / 44.50	$	24,000
10/2020 - 02/2021	NYMEX	Oil (bbls)	75,000	38.00 / 44.25	$	28,350
10/2020 - 02/2021	NYMEX	Oil (bbls)	75,000	38.00 / 44.00	$	22,500
10/2020 - 02/2021	NYMEX	Oil (bbls)	48,000	38.00 / 44.50	$	22,320
10/2020 - 02/2021	Henry Hub	Gas (MMBtu)	320,000	2.50 / 3.05	$	(30,871	)
					$	66,299

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

Note 8. Capital Contribution and Partners’ Equity

At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, and the General Partner received Incentive Distribution Rights (defined below).

The Partnership completed its best-efforts offering of common units on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership had completed the sale of approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offerings costs of $349.6 million.

Under the agreement with David Lerner Associates, Inc. (the “Dealer Manager”), the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold through the best-efforts offering, the total contingent fee is a maximum of approximately $15.0 million.

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

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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 unit, regardless of the amount paid for the unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

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

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

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

In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to recent market volatility and the impact on the Partnership’s operating cash flows. The Partnership will accumulate unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs, as defined above. As of September 30, 2020, the unpaid Payout Accrual totaled $0.828493 per common unit, or approximately $16 million. As discussed in Note 4. Debt and pursuant to the Letter Agreement, the Partnership is not permitted to pay distributions without lender approval.

For the nine months ended September 30, 2020, the Partnership paid distributions of $0.241644, or $4.6 million. For the three and nine months ended September 30, 2019, the Partnership paid distributions of $0.349041 and $1.047123 per common unit, or $6.6 million and $19.9 million, respectively.

Note 9. Related Parties

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

As described in Note 4. Debt, in July 2020, the Partnership entered into a loan agreement with GKDML, which provided for a $15 million unsecured, one-year Term Loan. GKDML is owned and managed by Messrs. Knight and McKenney, the Chief Executive Officer and the Chief Financial Officer, respectively, of the General Partner. To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A., which has substantially the same terms as the Term Loan and is personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and will not receive any consideration for providing the Term Loan or the guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimburse GKDML for all costs of its loan with Bank of America.

For the three and nine months ended September 30, 2020, approximately $101,000 and $291,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At September 30, 2020, approximately $101,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets. For the three and nine months ended September 30, 2019, approximately $88,000 and $236,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership.

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The members of the General Partner are affiliates of Mr. Knight, Mr. McKenney, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Messrs. Knight and McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. On January 31, 2018, the Partnership entered into a cost sharing agreement with ER12 that gives ER12 access to the Partnership’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The shared day-to-day costs are split evenly between the two partnerships and any direct third-party costs are paid by the party receiving the services. The shared costs are based on actual costs incurred with no mark-up or profit to the Partnership. The agreement may be terminated at any time by either party upon 60 days written notice.

The Partnership leases office space in Oklahoma City, Oklahoma on a month-to-month basis from an affiliate of the General Partner. For the three and six months ended June 30, 2020 and 2019, the Partnership paid $25,611 and $51,222 in each period, respectively, to the affiliate of the General Partner. The office space is shared between the Partnership and ER12; therefore, under the cost-sharing agreement, the monthly payment of $8,537 is split between the two partnerships. In addition to the office space, the cost-sharing agreement reduces the costs to the Partnership for accounting and asset management services provided through a member of the General Partner noted above. The compensation due to Clifford J. Merritt, President of the General Partner, is also a shared cost between the Partnership and ER12. For the three and nine months ended September 30, 2020, approximately $64,000 and $204,000, respectively, of expenses subject to the cost-sharing agreement were paid by the Partnership and have been or will be reimbursed by ER12. At September 30, 2020, the approximately $64,000 due to the Partnership from ER12 is included in Other current assets in the consolidated balance sheets. For the three and nine months ended September 30, 2019, approximately $65,000 and $200,000, respectively, of expenses subject to the cost sharing agreement were paid by the Partnership and have been reimbursed by ER12.

Note 10. Subsequent Events

In October 2020, ER12 provided 60-day written notice to the Partnership of ER12’s intention to terminate the cost sharing agreement between the Partnership and ER12. The cost sharing agreement will terminate on December 31, 2020.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

These forward-looking statements include such things as:

● the easing of COVID-19 and the return to pre-existing conditions following the ultimate recovery therefrom;

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

● the Partnership’s business strategy;

● estimated future distributions;

● estimated future capital expenditures;

● 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” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2019, those described under Part II. Item 1A. Risk Factors included herein this Form 10-Q and the following:

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

● the ability of the Partnership to meet its financial obligations due within one year;

● the ability of the Partnership to negotiate and receive future covenant waivers with its lender group under its Credit Facility, if necessary;

● the intentions of the Partnership’s operators with regard to possible curtailment or shut-in of the Partnership’s producing wells;

● 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 or refinancing debt for the Partnership’s drilling activities in a timely manner and on terms that are consistent with what the Partnership projects;

● 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 the Partnership’s production will not be effective.

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

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The following discussion and analysis should be read in conjunction with the Partnership’s Unaudited Consolidated Financial Statements and Notes thereto, appearing elsewhere in this Quarterly Report on Form 10-Q, as well as the information contained in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2019.

Overview

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

As of September 30, 2020, the Partnership owned an approximate 25% non-operated working interest in 243 producing wells, an estimated approximate 18% non-operated working interest in 21 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Substantially all of the Sanish Field Assets are operated by Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL) and Oasis Petroleum North America, LLC (“Oasis”) (NYSE: OAS), two publicly-traded oil and gas companies and two of the largest producers in the basin.

The Partnership has no officers, directors or employees. Instead, the General Partner manages the 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 officers.

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

During 2018, six wells were completed by the Partnership’s operators. Two wells were completed by and are being operated by Whiting; the Partnership has an approximate 29% non-operated working interest in these two wells. The other four wells were completed by and are operated by Oasis; the Partnership has an approximate 8% non-operated working interest in these four wells. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million.

During 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling and completion of 43 new wells in the Sanish field. Twenty-two (22) of these 43 wells have been completed and were producing at September 30, 2020; the Partnership has an approximate non-operated working interest of 23% in these 22 wells. The Partnership has an estimated approximate non-operated working interest of 18% in the remaining 21 wells that are in-process as of September 30, 2020. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 43 wells is approximately $63 million, of which approximately $42 million was incurred as of September 30, 2020. Due to the factors described below in “Current Price Environment,” Whiting suspended its Sanish field drilling program during the second quarter of 2020. See additional detail in “Oil and Natural Gas Properties” below.

Drilling Program, Oil Demand, Liquidity and Going Concern Considerations

In conjunction with the Whiting drilling program described above, the Partnership had incurred approximately $42 million in capital expenditures through September 30, 2020, which was primarily funded by availability under the Partnership’s $40 million revolving credit facility (“Credit Facility”, described in “Financing” below). However, the Partnership used all availability under its Credit Facility by March 31, 2020, and as of June 30, 2020, the Partnership had approximately $20 million in accrued operating and capital expenditures due to Whiting. New production from completed wells was expected to enhance the Partnership’s operating performance throughout 2020, providing incremental cash flow from operations to fund the Partnership’s investment in its undrilled acreage. Subsequent to the Partnership’s election to participate in Whiting’s drilling program, several factors, described in “Current Price Environment” below, have had and are anticipated to have an adverse impact on the Partnership’s business and its financial condition. Due to these severe negative impacts to the global oil and gas industry, Whiting declared bankruptcy under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas on April 1, 2020, then subsequently suspended its Sanish field drilling program during the second quarter of 2020.

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In July 2020, the Partnership entered into a loan agreement for a one year, $15 million term loan (“Affiliate Loan”) that matures on July 21, 2021 (see “Financing” below). The Partnership used proceeds from the Affiliate Loan plus cash on hand to pay the Partnership’s accrued operating and capital expenditures due to Whiting, which totaled approximately $19 million at the time of payment. In addition to the Affiliate Loan, the Partnership entered into a letter agreement (“Letter Agreement”) with its lender group for its Credit Facility. The Letter Agreement, among other items, waived the non-compliance of certain covenants under the Credit Facility; however, the Letter Agreement changed the maturity date of the Credit Facility from September 30, 2022 to July 31, 2021. In October 2020, the Partnership made a principal payment on the Affiliate Loan of $5 million; therefore, the Partnership’s outstanding debt obligations at the date of filing of this Form 10-Q total $50 million and mature within one year of the filing of this Form 10-Q.

The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) the Partnership’s ability to comply with its obligations under its loan agreements; (ii) refinancing its existing debt and/or securing additional capital; (iii) an increase in demand for oil and natural gas as the global economy recovers from the effects of the COVID-19 pandemic and the existing oversupply of oil in the United States; and (iv) an increase in oil and natural gas market prices, which will improve the Partnership’s cash flow generated from operations. The Partnership can provide no assurance that it will be able to achieve any of these objectives. Refinancing its existing debt or securing additional capital may not be available on favorable terms to the Partnership, if it is available at all. There also can be no assurance that economic activity and oil and natural gas market conditions, including commodity prices, will return to pre-COVID-19 levels, or that the Partnership will be able to meet its operational obligations. If the Partnership is unable to refinance or repay its debt obligations or is unable to meet its operational obligations, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy these obligations, which create the substantial doubt that exists about the ability of the Partnership to continue as a going concern for one year after the date these financial statements are issued.

Current Price Environment

Historically, worldwide oil and natural gas prices and markets have been subject to significant change and volatility and will continue to be in the future. Since first being reported in December 2019, COVID-19 spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries, creating extreme volatility in capital markets and the global economy. Because of COVID-19’s impact to the global economy, demand for fossil fuels substantially declined during the first quarter of 2020, and demand remained depressed during the second quarter of 2020. Although prices for oil and natural gas stabilized in June 2020 and throughout the third quarter of 2020, prices remain below pre-COVID-19 levels and are not anticipated to return to pre-COVID-19 levels during 2020.

In addition to the outbreak of COVID-19 during the first quarter of 2020, Saudi Arabia and Russia, two of the largest worldwide producers of crude oil, engaged in a price war during March and April 2020. Russia did not participate in production cuts coordinated by the Organization of the Petroleum Exporting Countries (“OPEC”), which led to Saudi Arabia lowering crude oil prices and both countries substantially increasing daily output of crude oil. The increase in Saudi and Russian oil output along with sustained production by other global producers, including the United States, has stressed the oil and gas industry’s capacity to store excess oil and gas. Despite Saudi Arabia, Russia, the United States and other OPEC members reaching an agreement in April 2020 to cut daily production, congested supply chain channels and excess crude oil and natural gas inventory are expected to weigh negatively on commodity prices while demand remains low during COVID-19.

These factors led to oil prices falling to 20-year lows in April 2020, when the average daily NYMEX futures closing prices for the month was $16.70. In response to lower commodity prices and reduced demand, operators within the United States altered drilling programs and the related forecasted capital expenditures for those programs, and implemented other cost-saving measures, such as curtailing production or shutting in producing wells, during the second quarter of 2020. While operators have since returned significant inventory of existing wells to production, the nature and timing of drilling new wells remains uncertain. The Partnership’s revenues and cash flow from operations are highly sensitive to changes in oil and natural gas prices and to levels of production. As a result, sustained lower prices have and will continue to impact the amount of capital the Partnership has available for the development of its undrilled wellsites. In addition to commodity price fluctuations, despite the addition of new wells discussed above, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.

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The following table lists average NYMEX prices for oil and natural gas for the three and nine months ended September 30, 2020 and 2019.

	Three Months Ended September 30,				Percent Change			Nine Months Ended September 30,				Percent Change
	2020		2019					2020		2019
Average market closing prices (1)
Oil (per Bbl)	$	40.91	$	56.44		-27.5	%	$	38.22	$	57.01		-33.0	%
Natural gas (per Mcf)	$	2.00	$	2.38		-16.0	%	$	1.87	$	2.62		-28.6	%

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

Results of Operations

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 (“NGL” or “NGLs”), (3) production costs per BOE and (4) capital expenditures.

The following is a summary of the results from operations, including production, of the Partnership’s non-operated working interest for the three and nine months ended September 30, 2020 and 2019.

	Three Months Ended September 30,													Nine Months Ended September 30,
	2020		Percent of Revenue			2019		Percent of Revenue			Percent Change			2020		Percent of Revenue			2019		Percent of Revenue			Percent Change
Total revenues	$	9,650,268		100.0	%	$	7,339,109		100.0	%		31.5	%	$	25,506,320		100.0	%	$	26,748,113		100.0	%		-4.6	%
Production expenses		2,825,472		29.3	%		2,228,933		30.4	%		26.8	%		6,997,839		27.4	%		7,977,046		29.8	%		-12.3	%
Production taxes		777,012		8.1	%		558,288		7.6	%		39.2	%		2,185,903		8.6	%		2,132,056		8.0	%		2.5	%
Depreciation, depletion, amortization and accretion		6,112,621		63.3	%		2,767,479		37.7	%		120.9	%		16,575,336		65.0	%		9,403,364		35.2	%		76.3	%
General, administration and other expense		379,569		3.9	%		281,308		3.8	%		34.9	%		1,300,003		5.1	%		1,043,293		3.9	%		24.6	%
Production (BOE):
Oil		245,522					134,533					82.5	%		760,284					457,259					66.3	%
Natural gas		52,789					34,343					53.7	%		123,978					116,857					6.1	%
Natural gas liquids		44,573					24,807					79.7	%		112,797					99,726					13.1	%
Total		342,884					193,683					77.0	%		997,059					673,842					48.0	%
Average sales price per unit:
Oil (per Bbl)	$	33.35				$	49.43					-32.5	%	$	29.48				$	49.45					-40.4	%
Natural gas (per Mcf)		2.01					2.08					-3.4	%		1.87					2.95					-36.6	%
Natural gas liquids (per Bbl)		18.53					10.49					76.6	%		15.08					20.75					-27.3	%
Combined (per BOE)		28.14					37.89					-25.7	%		25.58					39.69					-35.6	%
Average unit cost per BOE:
Production expenses		8.24					11.51					-28.4	%		7.02					11.84					-40.7	%
Production taxes		2.27					2.88					-21.4	%		2.19					3.16					-30.7	%
Depreciation, depletion, amortization and accretion		17.83					14.29					24.8	%		16.62					13.95					19.1	%
Capital expenditures	$	416,882				$	5,957,663							$	18,564,273				$	7,808,174

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Oil, Natural Gas and NGL Revenues

For the three months ended September 30, 2020, revenues for oil, natural gas and NGL sales were $9.7 million. Revenues for the sale of crude oil were $8.2 million, which resulted in a realized price of $33.35 per barrel. Revenues for the sale of natural gas were $0.6 million, which resulted in a realized price of $2.01 per Mcf. Revenues for the sale of NGLs were $0.8 million, which resulted in a realized price of $18.53 per BOE of sold production. For the three months ended September 30, 2019, revenues for oil, natural gas and NGL sales were $7.3 million. Revenues for the sale of crude oil were $6.6 million, which resulted in a realized price of $49.43 per barrel. Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $2.08 per Mcf. Revenues for the sale of NGLs were $0.3 million, which resulted in a realized price of $10.49 per BOE of sold production.

For the nine months ended September 30, 2020, revenues for oil, natural gas and NGL sales were $25.5 million. Revenues for the sale of crude oil were $22.4 million, which resulted in a realized price of $29.48 per barrel. Revenues for the sale of natural gas were $1.4 million, which resulted in a realized price of $1.87 per Mcf. Revenues for the sale of NGLs were $1.7 million, which resulted in a realized price of $15.08 per BOE of sold production. For the nine months ended September 30, 2019, revenues for oil, natural gas and NGL sales were $26.7 million. Revenues for the sale of crude oil were $22.6 million, which resulted in a realized price of $49.45 per barrel. Revenues for the sale of natural gas were $2.1 million, which resulted in a realized price of $2.95 per Mcf. Revenues for the sale of NGLs were $2.1 million, which resulted in a realized price of $20.75 per BOE of sold production.

The realized prices per barrel of oil above are based upon the NYMEX benchmark price less a cost to distribute the oil, or the differential. Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation methods out of the Sanish field. Due to produced oil from the Sanish field exceeding demand and reduced storage capacity available at refineries, the Partnership’s oil price differential increased during the second quarter of 2020. However, as market supply and demand imbalances began to stabilize in July 2020, the Partnership’s oil price differential returned to historical levels during the third quarter of 2020. In July 2020, a federal judge ruled that two significant pipelines that transport oil and natural gas from North Dakota fields, including the Sanish field, must suspend operations due to environmental review and disputes over right to use land owned by Native Americans (this ruling was later stayed on appeal and the case remains active in court). If use of the region pipelines is suspended at a future date, the Partnership anticipates its differential would increase. Realized sales prices for natural gas and NGLs were also negatively impacted in 2020 due to processing and transportation constraints, discussed above in “Current Price Environment” and below in “Production Expenses”, as product leaves the Sanish field.

The Partnership’s results for the three and nine months ended September 30, 2020 were negatively impacted by the Partnership’s realized sales prices for oil, natural gas and NGLs, which decreased in line with market commodity prices described in “Current Price Environment” above, in comparison to the same periods of 2019. However, the Partnership’s increase in sold production volumes for the three and nine months ended September 30, 2020 helped offset the negative impact of lower realized sales prices. The Partnership has completed 22 new wells since the fourth quarter of 2019, which led to increases in the Partnership’s sold production volumes of oil, natural gas and NGLs when compared to the same periods of 2019 (during the third quarter of 2019, production from some of the Partnership’s existing producing wells was temporarily suspended to allow for the commencement of drilling wells now complete on the Partnership’s acreage). In addition, the Partnership’s operators did not curtail production or shut-in a significant number of producing wells during the second quarter of 2020, so the Partnership has benefited from stable production throughout 2020. Sold production for the Sanish Field Assets was approximately 3,700 BOE per day and 3,600 BOE per day for the three and nine months ended September 30, 2020, respectively, while sold production was approximately 2,100 BOE and 2,500 BOE per day for the three and nine months ended September 30, 2019, respectively.

If commodity prices fall from current levels and operators are unable to produce, process and sell oil and natural gas at economical prices, the operators in the Sanish field may curtail daily production, shut-in producing wells or seek other cost-cutting measures, and could continue so long as producing is uneconomical. Consequently, any of these measures could significantly impact the Partnership’s oil, natural gas and NGL production. If certain wells are shut-in, 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. The Partnership has 21 wells currently in various stages of drilling and completion, and the timing of completion of these wells is unknown at this time. Therefore, the Partnership will experience natural production declines until market conditions improve and the 21 in-process wells are completed.

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Operating Costs and Expenses

Production Expenses

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

For the three months ended September 30, 2020 and 2019, production expenses were $2.8 million and $2.2 million, respectively, and production expenses per BOE of sold production were $8.24 and $11.51, respectively. For the nine months ended September 30, 2020 and 2019, production expenses were $7.0 million and $8.0 million, respectively, and production expenses per BOE of sold production were $7.02 and $11.84, respectively. Production expenses per BOE for the three and nine months ended September 30, 2020 were below the prior year expenses of the same periods per BOE primarily due to (i) an increase in sold production volumes along with fixed lease operating expenses; (ii) other operating cost-saving measures implemented by the Partnership’s operators while market commodity prices are depressed; and (iii) certain of the Partnership’s existing producing wells being temporarily suspended for the development of new wells, as noted above, or workover repairs.

Production Taxes

Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. Production taxes for the three months ended September 30, 2020 and 2019 were $0.8 million (8% of revenue) and $0.6 million (8% of revenue), respectively. Production taxes for the nine months ended September 30, 2020 and 2019 were $2.2 million (9% of revenue) and $2.1 million (8% of revenue), respectively. Production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGL to total sales. Taxes on the sale of gas and NGL products are less than taxes levied on the sale of oil.

Depreciation, Depletion, Amortization and Accretion (“DD&A”)

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. DD&A for the three months ended September 30, 2020 and 2019 was $6.1 million and $2.8 million, and DD&A per BOE of sold production was $17.83 and $14.29, respectively. DD&A for the nine months ended September 30, 2020 and 2019 was $16.6 million and $9.4 million, and DD&A per BOE of sold production was $16.62 and $13.95, respectively. The increase in DD&A expense per BOE of production is primarily due to the decrease of the Partnership’s estimated proved undeveloped reserves (“PUDs”) resulting from (i) changes to the Partnership’s future drilling schedule and (ii) investment in new wells during the fourth quarter of 2019 and first quarter of 2020. 

General and Administrative Costs

General and administrative costs for the three months ended September 30, 2020 and 2019 were $0.4 million and $0.3 million, respectively. General and administrative costs for the nine months ended September 30, 2020 and 2019 were $1.3 million and $1.0 million, respectively. The principal components of general and administrative expense are accounting, legal and consulting fees. The increase in general and administrative costs for the three- and nine-month periods ended September 30, 2020, compared to the same periods of 2019, is primarily due to higher legal fees incurred to protect the Partnership’s rights under joint operating agreements with its operators.

Gain on Derivatives

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Periodically, the Partnership utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations. The Partnership settled three derivative contracts during the first quarter of 2020, and in accordance with the Letter Agreement discussed in “Financing” below, the Partnership is required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021). In August 2020, the Partnership established its risk management program by entering into costless collar derivative contracts for future oil and natural gas produced by the Sanish Field Assets during the period from August 2020 through February 2021.

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

	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Settlements on matured derivatives	$	28,000	$	-	$	285,040	$	-
Gain on mark-to-market of derivatives		66,299		498,790		250,149		498,790
Gain on derivatives	$	94,299	$	498,790	$	535,189	$	498,790

The Partnership realized gains of approximately $28,000 on the settlement of matured derivative contracts during the three months ended September 30, 2020. Settlement gains are calculated as the difference between the contract price and the market settlement price. The Partnership’s oil production contracts that expired during the three months ended September 30, 2020 represented 122,000 barrels of oil; however, these oil production contracts were settled at no cost or benefit to the Partnership, as the contract price on the date of settlement was within the established floor and ceiling prices. The Partnership’s natural gas production contracts that expired during the three months ended September 30, 2020 represented 140,000 Mcf of produced natural gas, and settlement gains were $28,000, or $0.20 per Mcf.

The Partnership realized gains of approximately $285,000 on the settlement of matured derivative contracts during the nine months ended September 30, 2020. The Partnership’s oil production contracts that expired during the nine months ended September 30, 2020 represented 204,000 barrels of oil, and settlement gains were approximately $257,000, or $1.26 per barrel of oil. The Partnership’s natural gas production contracts that expired during the nine months ended September 30, 2020 represented 140,000 Mcf of produced natural gas, and settlement gains were $28,000, or $0.20 per Mcf.

The mark-to-market gains recorded for the three- and nine-month periods ended September 30, 2020 and 2019 represent the change in fair value of the Partnership’s derivative instruments held at period-end. These unrealized gains do not represent actual settlements and no payments were made to the counterparty.

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

Settlement Period	Product	Costless Collar Volumes	Floor / Ceiling Prices ($)
10/2020 - 02/2021	Oil (bbls)	75,000	37.50 / 44.50
10/2020 - 02/2021	Oil (bbls)	75,000	38.00 / 44.25
10/2020 - 02/2021	Oil (bbls)	75,000	38.00 / 44.00
10/2020 - 02/2021	Oil (bbls)	48,000	38.00 / 44.50
10/2020 - 02/2021	Gas (MMBtu)	320,000	2.50 / 3.05

Interest Expense, Net

Interest expense, net, for the three months ended September 30, 2020 and 2019 was $0.5 million and $0.2 million, respectively. Interest expense, net, for the nine months ended September 30, 2020 and 2019 was $1.4 million and $0.6 million, respectively. The primary components of Interest expense, net, during the three- and nine-month periods ended September 30, 2020 was interest expense on the Credit Facility and the Affiliate Loan discussed below in “Financing.” The primary component of Interest expense, net during the three- and nine-month periods ended September 30, 2019 was interest expense on the Credit Facility. The addition of the Affiliate Loan along with increased borrowings and an increase to the interest rate of the Partnership’s existing Credit Facility under the Letter Agreement, discussed below in “Financing”, resulted in an increase to the Partnership’s interest expense during the three and nine months ended September 30, 2020, as compared to the same periods of 2019.

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Supplemental Non-GAAP Measure

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

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

The following table reconciles the Partnership’s GAAP net income to Adjusted EBITDAX for the three and nine months ended September 30, 2020 and 2019.

	Three Months Ended September 30, 2020			Three Months Ended September 30, 2019			Nine Months Ended September 30, 2020			Nine Months Ended September 30, 2019
Net income (loss)	$	(879,896	)	$	1,794,044		$	(2,387,990	)	$	6,093,081
Interest expense, net		529,789			207,847			1,370,418			598,063
Depreciation, depletion, amortization and accretion		6,112,621			2,767,479			16,575,336			9,403,364
Exploration expenses		-			-			-			-
Non-cash gain on mark-to-market of derivatives		(66,299	)		(498,790	)		(250,149	)		(498,790	)
Adjusted EBITDAX	$	5,696,215		$	4,270,580		$	15,307,615		$	15,595,718

Liquidity and Capital Resources

Historically, the Partnership’s principal sources of liquidity were cash on hand, the cash flow generated from the Sanish Field Assets, and availability under the Partnership’s revolving credit facility, if any. As of September 30, 2020, the Partnership had borrowed $40 million under its revolving credit facility, which represents all availability under the revolving credit facility. In July 2020, the Partnership utilized the proceeds from an affiliate term loan (described below in “Financing”) and cash on hand to repay amounts outstanding to Whiting of approximately $19 million (upon payment of the outstanding amounts, Whiting released all liens it had asserted against the Sanish Field Assets). At September 30, 2020, the Partnership held unrestricted cash and cash equivalents of $5.3 million and for the nine months ended September 30, 2020, the Partnership generated $15.1 million in cash flows from operations. As discussed in “Drilling Program, Oil Demand, Liquidity, and Going Concern Considerations” above, there are no assurances that cash on hand and cash flow from operations will be sufficient to continue to fund the Partnership’s operations and repay its indebtedness, described in “Financing” below.

Financing

Revolving Credit Facility

At September 30, 2020, the Partnership’s outstanding balance on the Credit Facility was $40 million, and the interest rate for the Credit Facility was 4.25%.

On July 21, 2020, the Partnership entered into the Letter Agreement with its lending group that amended and modified the Credit Facility. The modifications include, among other items, the following:

- Maturity date was changed from September 30, 2022 to July 31, 2021;

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- Interest rate was changed to the prime rate plus 1.00%, with an interest rate floor of 4.00% (an increase of 50 basis points from the rate prior to the Letter Agreement);

- Any future Partnership distributions to limited partners require Lender approval;

- Calculation of the current ratio covenant was suspended until the reporting date for September 30, 2020;

- The definition of current ratio excludes the Affiliate Loan (discussed below) from the definition of liabilities; and

- As additional collateral for the loan, the Partnership established and funded a bank account with Lender in the amount of $1.6 million, to be used for interest payments under the Amended Loan Agreement until maturity (the balance of this collateral bank account at September 30, 2020 was approximately $1.3 million and is included in Restricted cash and cash equivalents on the Partnership’s September 30, 2020 consolidated balance sheet).

In addition to the modification of certain terms of the Credit Facility, the Letter Agreement waived the defaults by the Partnership under the Amended Loan Agreement that existed prior to signing the Letter Agreement, including not meeting the current ratio covenant as of March 31, 2020, the Partnership not filing its first quarter financial statements within 60 days of March 31, 2020 and the non-payment by the Partnership of amounts due to Whiting. The Letter Agreement also waived the Partnership’s calculation of the current ratio covenant at June 30, 2020. The Letter Agreement also allowed for the Affiliate Loan discussed below and payments under the Affiliate Loan.

In consideration for the modifications, amendments and waivers described above to the Amended Loan Agreement, the Letter Agreement provides for an amendment fee to Lender of $40,000, of which $15,000 was paid on September 30, 2020 and $25,000 is due December 31, 2020.

The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include:

● A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00

● A minimum ratio of current assets to current liabilities of 1.00 to 1.00 (“Current Ratio”)

● A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period

The Partnership was in compliance with its applicable covenants at September 30, 2020. If the Partnership is not in compliance with its covenants in future periods, it may not be able to obtain waivers and the outstanding balance under the Credit Facility may become due on demand at that time. See additional information in “Note 4. Debt” in Part I, Item 1 of this Form 10-Q.

Term Loan from Affiliate

On July 21, 2020, the Partnership, as borrower, entered into a loan agreement with GKDML, LLC (“GKDML”), which provides for an unsecured, one-year term loan (“Term Loan” or “Affiliate Loan”) in the amount of $15 million. GKDML is owned and managed by Glade M. Knight and David S. McKenney, the Chief Executive Officer and the Chief Financial Officer, respectively, of the General Partner. The Term Loan bears interest at a variable rate based on LIBOR plus a margin of 2.00%, with a LIBOR floor of 0%. Interest is payable monthly. The Term Loan contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. At September 30, 2020, the outstanding balance on the Term Loan was $15 million, the interest rate for the Term Loan was approximately 2.2% and the Partnership was in compliance of all applicable covenants.

To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A. on July 21, 2020 (“GKDML Loan”). The GKDML Loan has substantially the same terms as the Term Loan and is personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and will not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimburse GKDML for all costs of the GKDML Loan. The Term Loan may be prepaid at any time with no penalty and in any amount, but any amounts repaid may not be reborrowed. The Partnership anticipates utilizing cash from operations to reduce outstanding balances under the Term Loan.

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Partners’ Equity

The Partnership completed its best-efforts offering of common units on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership sold approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.

Under the agreement with the Dealer Manager, the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold in the offering, the total contingent fee is a maximum of approximately $15.0 million, which will only be paid if Payout occurs, as defined in “Note 8. Capital Contribution and Partners’ Equity” in Part I, Item 1 of this Form 10-Q.

Distributions

In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to recent market volatility and the impact on the Partnership’s operating cash flows. The Partnership will accumulate unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs. As of September 30, 2020, the unpaid Payout Accrual totaled $0.828493 per common unit, or approximately $16 million. As discussed in “Financing” above and pursuant to the Letter Agreement, the Partnership is not permitted to pay distributions without lender approval.

For the nine months ended September 30, 2020, the Partnership paid distributions of $0.241644, or $4.6 million. For the three and nine months ended September 30, 2019, the Partnership paid distributions of $0.349041 and $1.047123 per common unit, or $6.6 million and $19.9 million, respectively. 

Oil and Natural Gas Properties

The Partnership incurred approximately $18.6 million and $7.8 million in capital expenditures for the nine months ended September 30, 2020 and 2019, respectively.

During the second half of 2019 and the first quarter of 2020, the Partnership elected to participate in drilling and completion of 43 new wells at an estimated cost to the Partnership of approximately $63 million. Through September 30, 2020, the Partnership has incurred approximately $42 million in capital expenditures related to the 43 wells. As of September 30, 2020, 22 of these wells have been completed and 21 were in process. The Partnership anticipates that the remaining 21 in-process wells will remain in drilled, but uncompleted (“DUC”) status through the end of 2020, and the timing for completion of these DUC wells is dependent upon an increase in commodity pricing. The Partnership estimates it will incur approximately $1 to $2 million in additional capital expenditures during the fourth quarter of 2020. However, the factors described in “Current Price Environment” along with the uncertainty of when Whiting will resume its drilling program after emerging from bankruptcy protection in September 2020 make it difficult to predict the amount and timing of capital expenditures for the remainder of 2020 and into the first half of 2021, and estimated capital expenditures could be significantly different from amounts actually invested.

As discussed in “Drilling Program, Oil Demand, Liquidity and Going Concern Considerations”, the Partnership’s liquidity is currently dependent upon cash from operations and if it is not able to generate sufficient cash to fund capital expenditures, it may not be able to complete is obligations under the currently suspended drilling program or participate fully in future wells. Based upon information from its operators, development during through the first half of 2020 and a reduction in commodity prices, the Partnership decreased its proved undeveloped reserves (“PUD”) from 11,980 MBOE at December 31, 2019 to 2,737 MBOE at June 30, 2020. Approximately 63% of this decrease in PUD reserve volumes was the result of a change in the planned timing of the drilling and completion of PUD reserve locations outside of the SEC five-year window, while the remaining 37% of the decrease resulted from PUD conversion to proved developed reserves and lower oil and natural gas prices. The Partnership did not make any further drill schedule adjustments during the third quarter of 2020.

26

In addition to the approximate $21 million in estimated capital expenditures to be incurred for the drilling and completion of the 43 wells in which the Partnership has elected to participate (upon resumption of the drilling program), the Partnership anticipates that it may be obligated to invest $25 to $30 million in capital expenditures from 2021 through 2024 to participate in new well development in the Sanish Field without becoming subject to non-consent penalties under the joint operating agreements governing the Sanish Field Assets. If an operator elects to complete drilling or other significant capital expenditure activity and the Partnership is unable to fund the capital expenditures, the General Partner may decide to farmout the well. Also, if a well is proposed under the operating agreement for one of the properties the Partnership owns, the General Partner may elect to “non-consent” the well. Non-consenting a well will generally cause the Partnership not to be obligated to pay the costs of the well, but the Partnership will not be entitled to the proceeds of production from the well until a penalty is received by the parties that drilled the well.

Transactions with Related Parties

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

See further discussion in “Note 9. Related Parties” in Part I, Item 1 of this Form 10-Q.

Subsequent Events

In October 2020, ER12 provided 60-day written notice to the Partnership of ER12’s intention to terminate the cost sharing agreement between the Partnership and ER12. The cost sharing agreement will terminate on December 31, 2020.

27

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership has variable interest rates on its Credit Facility and Affiliate Loan that are subject to market changes in interest rates. Information regarding the Partnership’s Credit Facility and Affiliate Loan is contained in Item 1 – Financial Statements (Unaudited) and Notes to Consolidated Financial Statements: Note 4. Debt and Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, appearing elsewhere within this Quarterly Report on Form 10-Q.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a–15 and 15d–15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Partnership carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, of the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of September 30, 2020 to provide reasonable assurance that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Partnership’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in the Partnership’s internal controls over financial reporting that occurred during the quarterly period ended September 30, 2020 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal controls over financial reporting.

28

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors

The Partnership’s potential risks and uncertainties are discussed in Item 1A. Risk Factors in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2019. The information below updates, and should be read in conjunction with, the risk factors and information disclosed in the Partnership’s 2019 Form 10-K. Except as presented below, there have been no material changes from the risk factors described in our 2019 Form 10-K.

The Partnership may not be able to obtain waivers of future covenant violations under its Credit Facility.

In July 2020, the Partnership received a waiver from its lender group that suspended the calculation of the current ratio covenant until September 30, 2020 and waived certain other defaults under the Credit Facility. If the Partnership violates covenants under the Credit Facility in the future and is unable to obtain waivers, the lenders will have the right to accelerate all of the outstanding indebtedness under the Credit Facility. If the lenders were to accelerate all of the obligations outstanding under the Credit Facility, the Partnership would be required to pay approximately $40 million (as of September 30, 2020) to the lenders. Additionally, the Partnership would be in default under its Affiliate Loan of $15 million.

The current widespread outbreak of COVID-19 has significantly adversely impacted and disrupted, and is expected to continue to adversely impact and disrupt, the Partnership’s business and the industry in which the Partnership operates.

In December 2019, China reported an outbreak of COVID-19 in its Wuhan province. On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States declared a national emergency with respect to COVID-19. COVID-19 has spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures include significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries, creating extreme volatility in capital markets and the global economy.

COVID-19’s impact to the global economy, in particular the oil and gas industry, has been unprecedented, as reduced demand for fossil fuels has resulted in a significant decline in commodity prices during March and April 2020. The Partnership experienced a decline in anticipated revenue during March 2020 and through the third quarter of 2020 due to commodity price declines, and the Partnership expects demand for oil and gas as well as commodity prices to be low for the remainder of 2020, which will negatively impact the Partnership’s business during the fourth quarter of 2020 and potentially beyond. The Partnership cannot give any assurance as to when demand will return to more normal levels or if commodity prices will increase.

The COVID-19 pandemic and related restrictions aimed at mitigating its spread have caused the General Partner to modify certain of the Partnership’s business practices, including limiting employee travel, encouraging work-from-home practices and other social distancing measures. Such measures may cause disruptions to the Partnership’s business and operational plans, which may include shortages of employees, contractors and subcontractors. There is no certainty that these or any other future measures will be sufficient to mitigate the risks posed by the disease, including the risk of infection of key employees, and the Partnership’s ability to perform certain functions could be impaired by these new business practices. For example, the Partnership’s reliance on technology has necessarily increased due to the General Partner’s encouragement of remote communications and other work-from-home practices, which could make the Partnership more vulnerable to cyber-attacks.

29

The spread of COVID-19 has caused severe disruptions in the global economy, specifically the oil and gas industry, and could potentially create widespread business continuity issues of an as yet unknown magnitude and duration.

COVID-19 has caused severe economic, market and other disruptions worldwide. In many respects, it is too early to quantify the long-term ramifications of COVID-19 on the global economy as well as oil and gas industry, the Partnership’s operators and the Partnership’s business. Further, it is currently not possible to predict how long the COVID-19 pandemic will last or the time that it will take for economic activity to return to prior levels. As a result, the Partnership cannot provide an estimate of the overall impact of COVID-19 on its business or when, or if, the Partnership and its operators will be able to resume normal, pre-COVID-19 operations. Nevertheless, sustained lower oil and gas prices and reduced demand resulting from COVID-19 present material uncertainty and risk with respect to the Partnership’s business, financial performance and condition, operating results and cash flows. In addition, low oil and natural gas prices may cause the Partnership’s undrilled wellsites to become uneconomic to develop.

Crude oil prices declined significantly in the first quarter of 2020 and into the second quarter of 2020. If oil prices remain at current levels or decline further for a prolonged period, the Partnership’s operations and financial condition may be materially and adversely affected.

In the first quarter of 2020 and through the beginning of the second quarter, crude oil prices fell sharply and dramatically, due in part to significantly decreased demand as a result of the COVID-19 pandemic and the significantly increased supply of crude oil as a result of a price war between Saudi Arabia and Russia. In April 2020, Saudi Arabia, Russia, the United States and other members of OPEC agreed to certain production cuts; however, these cuts are not expected to be enough to offset near-term demand loss attributable to the COVID-19 pandemic. Prices for WTI crude oil were over $60 per barrel at the beginning of 2020 before declining significantly through March and further declined as prices fell below $20 per barrel by the end of April 2020. Oil prices have stabilized around $40 per barrel since June 2020; however, if crude oil prices remain at current levels or further decline for a prolonged period, the Partnership’s operations, financial condition, cash flows, level of expenditures and the quantity of estimated proved reserves that may be attributed to the Partnership’s properties may be materially and adversely affected.

As domestic demand for crude oil has declined substantially due to COVID-19, the General Partner cannot ensure that there will be a physical market for the Partnership’s production at economic prices until markets stabilize.

As a result of low commodity prices, the operators of the Partnership’s wells have and may curtail a portion of the Partnership’s estimated crude oil production and may store rather than sell additional crude oil production in the near future. Additionally, an excess supply of oil could lead to further curtailments by those operators. While the Partnership believes that the shutting-in of such production will not impact the productivity of such wells when reopened, there is no assurance the Partnership will not have a degradation in well performance upon returning those wells to production. The storing or shutting in of a portion of the Partnership’s production can also result in increased costs under midstream and other contracts. Any of the foregoing could result in an adverse impact on the Partnership’s revenues, financial position and cash flows.

The Partnership has substantial liquidity needs and may not be able to obtain sufficient liquidity to continue as a going concern.

In addition to the cash requirements necessary to fund ongoing operations, including scheduled debt service obligations and payment of incurred capital expenditures and general and administrative costs, the Partnership may incur significant professional fees and other costs to obtain alternative financing. There can be no assurance that cash on hand and cash flows from operations in a period of sustained lower commodity prices will be sufficient to continue to fund the Partnership’s operations, including debt service, for any significant period of time.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Not applicable.

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

30

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit No.	Description
10.1	Letter Agreement dated July 21, 2020 between and among Energy 11, L.P. and Energy 11 Operating Company, LLC, collectively as Borrowers, and Simmons Bank, as Administrative Agent and Letter of Credit Issuer and the Lenders Signatory Party Hereto, collectively the Lenders (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on July 23, 2020)
10.2	Loan Agreement between GKDML, LLC, as lender, and Energy 11, L.P. and Energy 11 Operating Company, LLC, collectively Borrowers, dated July 21, 2020 (incorporated by reference from Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed on July 23, 2020)
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*
32.1	Certification of Chief Executive Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2	Certification of Chief Financial Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
101	The following materials from Energy 11, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Partners’ Equity, (iv) the Consolidated Statements of Cash Flows, and (v) related notes to these consolidated financial statements, tagged as blocks of text and in detail*
104	The cover page from the Partnership’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, formatted in iXBRL and contained in Exhibit 101

*Filed herewith.

31

SIGNATURES

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

Energy 11, L.P.
By: Energy 11 G.P., LLC, its General Partner
By:	/s/ Glade M. Knight
	Glade M. Knight
	Chief Executive Officer (Principal Executive Officer)
By:	/s/ David S. McKenney
	David S. McKenney
	Chief Financial Officer (Principal Financial and Accounting Officer)
Date: November 5, 2020

32

EX-31.1

EXHIBIT 31.1

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

I, Glade M. Knight, certify that:

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

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

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

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

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 5, 2020	By:	/s/ Glade M. Knight
	Name:	Glade M. Knight
	Title:	General Partner, Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

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

I, David McKenney, certify that:

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

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

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

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

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 5, 2020	By:	/s/ David S. McKenney
	Name:	David S. McKenney
	Title:	General Partner, Chief Financial Officer (Principal Financial and Accounting Officer)

EX-32.1

EXHIBIT 32.1

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

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

This certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and accompanies the Quarterly Report on Form 10-Q (the “Form 10-Q”) for the three months ended September 30, 2020 of Energy 11, L.P. (the “Partnership”).  I, Glade M. Knight, the Chief Executive Officer of the Partnership, certify that, based on my knowledge:

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

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

Date:  November 5, 2020	By:	/s/ Glade M. Knight
	Name:	Glade M. Knight
	Title:	General Partner, Chief Executive Officer (Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

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

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

This certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and accompanies the Quarterly Report on Form 10-Q (the “Form 10-Q”) for the three months ended September 30, 2020 of Energy 11, L.P. (the “Partnership”).  I, David McKenney, the Chief Financial Officer of the Partnership, certify that, based on my knowledge:

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

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

Date: November 5, 2020	By:	/s/ David S. McKenney
	Name:	David S. McKenney
	Title:	General Partner, Chief Financial Officer (Principal Financial and Accounting Officer)

XML

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2020	Nov. 05, 2020
Document Information Line Items
Entity Registrant Name	Energy 11, L.P.
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		18,973,474
Amendment Flag	false
Entity Central Index Key	0001581552
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Period End Date	Sep. 30, 2020
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q3
Entity Small Business	true
Entity Emerging Growth Company	true
Entity Shell Company	false
Entity Ex Transition Period	true
Document Quarterly Report	true
Document Transition Report	false
Entity File Number	000-55615
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-3070515
Entity Address, Address Line One	120 W 3rd Street, Suite 220
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	882-9192
Title of 12(b) Security	None
Entity Interactive Data Current	Yes
No Trading Symbol Flag	true

XML

Consolidated Balance Sheets - USD ($)	Sep. 30, 2020	Dec. 31, 2019
Assets
Cash and cash equivalents	$ 5,254,981	$ 348,550
Restricted cash and cash equivalents	1,288,884	0
Oil, natural gas and natural gas liquids revenue receivable	4,714,775	5,857,926
Other current assets	418,001	284,652
Total Current Assets	11,676,641	6,491,128
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $69,699,954 and $53,186,165, respectively	328,844,767	326,758,636
Total Assets	340,521,408	333,249,764
Liabilities
Accounts payable, accrued expenses and other current liabilities	3,208,326	20,061,059
Revolving credit facility	40,000,000	0
Affiliate term loan	15,000,000	0
Total Current Liabilities	58,208,326	20,061,059
Revolving credit facility	0	24,000,000
Asset retirement obligations	1,549,927	1,452,734
Total Liabilities	59,758,253	45,513,793
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)	280,764,882	287,737,698
General partner's interest	(1,727)	(1,727)
Class B Units (62,500 units issued and outstanding, respectively)	0	0
Total Partners’ Equity	280,763,155	287,735,971
Total Liabilities and Partners’ Equity	$ 340,521,408	$ 333,249,764

XML

Consolidated Balance Sheets (Parentheticals) - USD ($)	Sep. 30, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars)	$ 69,699,954	$ 53,186,165
Limited partners' interest, common units issued	18,973,474	18,973,474
Limited partners' interest, common units outstanding	18,973,474	18,973,474
Class B Units, units issued	62,500	62,500
Class B Units, units outstanding	62,500	62,500

XML

Consolidated Statements of Operations - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Revenues
Oil	$ 8,187,180	$ 6,649,652	$ 22,412,183	$ 22,612,030
Natural gas	636,971	429,347	1,392,651	2,066,813
Natural gas liquids	826,117	260,110	1,701,486	2,069,270
Total revenue	9,650,268	7,339,109	25,506,320	26,748,113
Operating costs and expenses
Production expenses	2,825,472	2,228,933	6,997,839	7,977,046
Production taxes	777,012	558,288	2,185,903	2,132,056
General and administrative expenses	379,569	281,308	1,300,003	1,043,293
Depreciation, depletion, amortization and accretion	6,112,621	2,767,479	16,575,336	9,403,364
Total operating costs and expenses	10,094,674	5,836,008	27,059,081	20,555,759
Operating income (loss)	(444,406)	1,503,101	(1,552,761)	6,192,354
Gain on derivatives	94,299	498,790	535,189	498,790
Interest expense, net	(529,789)	(207,847)	(1,370,418)	(598,063)
Total other expense, net	(435,490)	290,943	(835,229)	(99,273)
Net income (loss)	$ (879,896)	$ 1,794,044	$ (2,387,990)	$ 6,093,081
Basic and diluted net income (loss) per common unit (in Dollars per share)	$ (0.05)	$ 0.09	$ (0.13)	$ 0.32
Weighted average common units outstanding - basic and diluted (in Shares)	18,973,474	18,973,474	18,973,474	18,973,474

XML

Consolidated Statements of Partners' Equity - USD ($)	Total	Limited Partner [Member]	General Partner [Member]	Capital Unit, Class B [Member] Member Units [Member]
Balance at Dec. 31, 2018	$ 305,745,602	$ 305,747,329	$ (1,727)
Balance (in Shares) at Dec. 31, 2018		18,973,474		62,500
Distributions declared and paid to common units	(6,622,520)	$ (6,622,520)
Net income (loss)	2,339,974	2,339,974
Balance at Mar. 31, 2019	301,463,056	$ 301,464,783	(1,727)
Balance (in Shares) at Mar. 31, 2019		18,973,474		62,500
Balance at Dec. 31, 2018	305,745,602	$ 305,747,329	(1,727)
Balance (in Shares) at Dec. 31, 2018		18,973,474		62,500
Distributions declared and paid to common units	(19,867,561)
Net income (loss)	6,093,081
Balance at Sep. 30, 2019	291,971,122	$ 291,972,849	(1,727)
Balance (in Shares) at Sep. 30, 2019		18,973,474		62,500
Balance at Mar. 31, 2019	301,463,056	$ 301,464,783	(1,727)
Balance (in Shares) at Mar. 31, 2019		18,973,474		62,500
Distributions declared and paid to common units	(6,622,521)	$ (6,622,521)
Net income (loss)	1,959,063	1,959,063
Balance at Jun. 30, 2019	296,799,598	$ 296,801,325	(1,727)
Balance (in Shares) at Jun. 30, 2019		18,973,474		62,500
Distributions declared and paid to common units	(6,622,520)	$ (6,622,520)
Net income (loss)	1,794,044	1,794,044
Balance at Sep. 30, 2019	291,971,122	$ 291,972,849	(1,727)
Balance (in Shares) at Sep. 30, 2019		18,973,474		62,500
Balance at Dec. 31, 2019	$ 287,735,971	$ 287,737,698	(1,727)
Balance (in Shares) at Dec. 31, 2019	18,973,474	18,973,474		62,500
Distributions declared and paid to common units	$ (4,584,826)	$ (4,584,826)
Net income (loss)	2,933,427	2,933,427
Balance at Mar. 31, 2020	286,084,572	$ 286,086,299	(1,727)
Balance (in Shares) at Mar. 31, 2020		18,973,474		62,500
Balance at Dec. 31, 2019	$ 287,735,971	$ 287,737,698	(1,727)
Balance (in Shares) at Dec. 31, 2019	18,973,474	18,973,474		62,500
Distributions declared and paid to common units	$ (4,584,826)
Net income (loss)	(2,387,990)
Balance at Sep. 30, 2020	$ 280,763,155	$ 280,764,882	(1,727)
Balance (in Shares) at Sep. 30, 2020	18,973,474	18,973,474		62,500
Balance at Mar. 31, 2020	$ 286,084,572	$ 286,086,299	(1,727)
Balance (in Shares) at Mar. 31, 2020		18,973,474		62,500
Net income (loss)	(4,441,521)	$ (4,441,521)
Balance at Jun. 30, 2020	281,643,051	$ 281,644,778	(1,727)
Balance (in Shares) at Jun. 30, 2020		18,973,474		62,500
Net income (loss)	(879,896)	$ (879,896)
Balance at Sep. 30, 2020	$ 280,763,155	$ 280,764,882	$ (1,727)
Balance (in Shares) at Sep. 30, 2020	18,973,474	18,973,474		62,500

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Consolidated Statements of Partners' Equity (Parentheticals) - $ / shares	3 Months Ended
	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019
Capital Unit, Class B [Member] | Member Units [Member]
Distributions declared and paid to common units, per unit	$ 0.241644	$ 0.349041	$ 0.369041	$ 0.349041

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Consolidated Statements of Cash Flows - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Cash flow from operating activities:
Net income	$ 1,794,044	$ (2,387,990)	$ 6,093,081
Depreciation, depletion, amortization and accretion	2,767,479	16,575,336	9,403,364
(Gain) / loss on mark-to-market of derivatives		(250,149)	(498,790)
Non-cash expenses, net		67,232	37,328
Oil, natural gas and natural gas liquids revenue receivable		1,143,151	2,412,723
Other current assets		(134,283)	(36,170)
Accounts payable and accrued expenses		39,550	(603,796)
Net cash flow provided by operating activities		15,052,847	16,807,740
Cash flow from investing activities:
Additions to oil and natural gas properties		(35,272,706)	(3,540,372)
Net cash flow used in investing activities		(35,272,706)	(3,540,372)
Cash flow from financing activities:
Proceeds from revolving credit facility		16,000,000	3,000,000
Proceeds from affiliate term loan		15,000,000	0
Distributions paid to limited partners	(6,622,520)	(4,584,826)	(19,867,561)
Net cash flow (used in) provided by financing activities		26,415,174	(16,867,561)
Decrease in cash and cash equivalents		6,195,315	(3,600,193)
Cash and cash equivalents, beginning of period		348,550	3,685,327
Cash and cash equivalents, end of period	$ 85,134	6,543,865	85,134
Interest paid		1,336,840	574,334
Accrued capital expenditures related to additions to oil and natural gas properties		$ 1,714,900	$ 4,366,105

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Partnership Organization

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

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

Note 1. Partnership Organization

Energy 11, L.P. (the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership completed its best-efforts offering on April 24, 2017 with a total of approximately 19.0 million common units sold for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.

As of September 30, 2020, the Partnership owned an approximate 25% non-operated working interest in 243 producing wells, an estimated approximate 18% non-operated working interest in 21 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL) and Oasis Petroleum North America, LLC (“Oasis”) (NYSE: OAS), two of the largest producers in the basin, operate substantially all of the Sanish Field Assets.

The general partner of the Partnership is Energy 11 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership.

The Partnership’s fiscal year ends on December 31.

Drilling Program, Oil Demand, Current Pricing, Liquidity and Going Concern Considerations

During 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling and completion of 43 new wells in the Sanish field. The Partnership estimates the total investment for these 43 new wells to be approximately $63 million. In conjunction with this drilling program performed primarily by Whiting, the Partnership had incurred approximately $42 million in capital expenditures through September 30, 2020, which was primarily funded by availability under the Partnership’s $40 million revolving credit facility (“Credit Facility”, described in Note 4. Debt). However, the Partnership used all availability under its Credit Facility by March 31, 2020, and as of June 30, 2020, the Partnership had approximately $20 million in accrued operating and capital expenditures due to Whiting. New production from completed wells was expected to enhance the Partnership’s operating performance throughout 2020, providing incremental cash flow from operations to fund the Partnership’s investment in its undrilled acreage.

Subsequent to the Partnership’s election to participate in Whiting’s drilling program, the outbreak of a novel coronavirus (“COVID-19”) in China spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries for an undetermined period of time, creating extreme volatility in capital markets and the global economy. Because of COVID-19’s impact to the global economy, demand for oil, natural gas and other hydrocarbons substantially declined in March 2020 and has remained depressed through the third quarter of 2020. Demand for oil and natural gas is not anticipated to return to pre-COVID-19 levels during 2020, and the outlook for demand for oil and natural gas in 2021 is uncertain. This reduction in demand compounded an existing excess in supply of oil and natural gas, as the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia could not agree on daily production output of crude oil in March 2020. As a result, Russia announced its intention to increase production, and Saudi Arabia immediately countered with announced reductions to export prices. All of these factors led to oil prices falling in March 2020 and to 20-year lows in April 2020. Although NYMEX oil prices have stabilized around $40 per barrel since June 2020, prices throughout the third quarter of 2020 remained below pre-COVID-19 levels.

In response to lower commodity prices and reduced demand, operators within the United States altered drilling programs and the related forecasted capital expenditures for those programs, and implemented other cost-saving measures, such as curtailing production or shutting in producing wells, during the second quarter of 2020. While operators have since returned significant inventory of existing wells to production, the nature and timing of drilling new wells remains uncertain. These factors have had and are anticipated to continue to have an adverse impact on the Partnership’s business and its financial condition. Due to the impacts to the global oil and gas industry described above, the General Partner approved the suspension of distributions to limited partners of the Partnership in March 2020. Further, Whiting and certain of its subsidiaries declared bankruptcy under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas on April 1, 2020. Subsequent to filing for Chapter 11 protection, Whiting suspended its Sanish field drilling program during the second quarter of 2020, but operated its business in the normal course without material disruption to its vendors, partners or employees, including the Partnership, during the bankruptcy process. Whiting completed its financial restructuring and emerged from bankruptcy protection in September 2020, but has yet to resume its drilling program.

In July 2020, the Partnership entered into a loan agreement for a one year, $15 million term loan (“Affiliate Loan”) that matures on July 21, 2021 (see Note 4. Debt for additional information). The Partnership used proceeds from the Affiliate Loan plus cash on hand to pay the Partnership’s accrued operating and capital expenditures due to Whiting, which totaled approximately $19 million at the time of payment. In addition to the Affiliate Loan, the Partnership entered into a letter agreement (“Letter Agreement”) with its lending group for its Credit Facility. The Letter Agreement, among other items, waived the non-compliance of certain covenants under the Credit Facility; however, the Letter Agreement changed the maturity date of the Credit Facility from September 30, 2022 to July 31, 2021. In October 2020, the Partnership made a principal payment on the Affiliate Loan of $5 million; therefore, the Partnership’s outstanding debt obligations at the date of filing of this Form 10-Q total $50 million and mature within one year of the filing of this Form 10-Q.

The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) the Partnership’s ability to comply with its obligations under its loan agreements (see Note 4. Debt for further discussion); (ii) refinancing its existing debt and/or securing additional capital; (iii) an increase in demand for oil and natural gas as the global economy recovers from the effects of the COVID-19 pandemic and the existing oversupply of oil in the United States; and (iv) an increase in oil and natural gas market prices, which will improve the Partnership’s cash flow generated from operations. The Partnership can provide no assurance that it will be able to achieve any of these objectives. Refinancing its existing debt or securing additional capital may not be available on favorable terms to the Partnership, if it is available at all. There also can be no assurance that economic activity and oil and natural gas market conditions, including commodity prices, will return to pre-COVID-19 levels, or that the Partnership will be able to meet its operational obligations. If the Partnership is unable to refinance or repay its debt obligations or is unable to meet its operational obligations, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy these obligations, which create the substantial doubt that exists about the ability of the Partnership to continue as a going concern for one year after the date these financial statements are issued.

The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Partnership to continue as a going concern.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

Note 2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements included in its 2019 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2020 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2020.

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.

Revenue Recognition

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

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

Net Income (Loss) Per Common Unit

Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (loss) per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and nine months ended September 30, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.

Recently Adopted Accounting Standards

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848), which provides optional guidance through December 31, 2022 to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments in ASU No. 2020-04 apply to contract modifications that replace a reference rate affected by reference rate reform, providing optional expedients regarding the measurement of hedge effectiveness in hedging relationships that have been modified to replace a reference rate. While the guidance in ASU No. 2020-04 became effective upon issuance, the provisions of the ASU did not have a material impact on the Partnership’s consolidated financial statements and related disclosures as of September 30, 2020.

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Oil and Natural Gas Investments

9 Months Ended

Sep. 30, 2020

Oil and Gas Property [Abstract]

Oil and Gas Properties [Text Block]

Note 3. Oil and Natural Gas Investments

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

During 2018, six wells were completed by the Partnership’s operators. Two wells were completed by and are being operated by Whiting; the Partnership has an approximate 29% non-operated working interest in these two wells. The other four wells were completed by and are operated by Oasis; the Partnership has an approximate 8% non-operated working interest in these four wells. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million.

During 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling and completion of 43 new wells in the Sanish field. Twenty-two (22) of these 43 wells have been completed and were producing at September 30, 2020; the Partnership has an approximate non-operated working interest of 23% in these 22 wells. The Partnership has an estimated approximate non-operated working interest of 18% in the remaining 21 wells that are in-process as of September 30, 2020. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 43 wells is approximately $63 million, of which approximately $42 million was incurred as of September 30, 2020. Whiting suspended its Sanish field drilling program during the second quarter of 2020 in response to the significant reduction in demand for oil caused by COVID-19 and the oversupply of oil in the United States. The Partnership estimates it may incur approximately $1 to $2 million in additional capital expenditures during the fourth quarter of 2020; however, low commodity prices, market supply and demand imbalances and how Whiting’s emergence from bankruptcy protection in September 2020 impacts the resumption of its suspended drilling program make it difficult to predict the amount and timing of capital expenditures for the remainder of 2020. Estimated capital expenditures could be significantly different from amounts actually invested.

Evaluation for Potential Impairment of Oil and Natural Gas Investments

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. The Partnership considered the declines in the current and forecasted operating cash flows resulting from COVID-19 and sustained lower commodity prices to be potential indicators of impairment and, as a result, performed a test of recoverability for the Sanish Field Assets. Estimated future net cash flows calculated in the recoverability test were based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows were based on NYMEX forward strip prices as of October 1, 2020, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believed will impact realizable prices. Future operating cost estimates were based on actual historical costs of the Sanish Field Assets. The Partnership’s recoverability analyses did not identify any impairment losses as of September 30, 2020.

If current macro-economic conditions continue or worsen, the carrying value of the Partnership’s oil and natural gas properties may not be recoverable and impairment losses could be recorded in future periods.

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Debt

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

Note 4. Debt

Revolving Credit Facility

On November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”) between and among the Partnership and Simmons Bank, as administrative agent and the lenders party thereto (the “Lender”), which provided for a revolving credit facility with an approved initial commitment amount of $20 million, subject to borrowing base restrictions. The maturity date was November 21, 2019. Effective September 30, 2019, the Partnership entered into an amendment and restatement of the Loan Agreement (the “Amended Loan Agreement”) with Lender, which provided for the Credit Facility with an approved initial commitment of $40 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The terms of the Amended Loan Agreement were generally similar to the Partnership’s existing revolving credit facility and included the following: (i) a maturity date of September 30, 2022; (ii) subject to certain exceptions, an interest rate, which did not change from the existing revolving credit facility, equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.50% to 3.50%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Amended Loan Agreement; (iii) an increase to the borrowing base from $30 million to an initially stipulated $40 million; and (iv) an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties.

At closing of the Amended Loan Agreement in October 2019, the Partnership paid an origination fee of 0.45% on the change in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000. The Partnership is also required to pay an unused facility fee of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter.

On July 21, 2020, the Partnership entered into a letter agreement (“Letter Agreement”) with Lender that amended and modified the Amended Loan Agreement. The modifications to the Amended Loan Agreement include, among other items, the following:

- Maturity date was changed from September 30, 2022 to July 31, 2021;

- Interest rate was changed to the prime rate plus 1.00%, with an interest rate floor of 4.00% (an increase of 50 basis points from the rate prior to the Letter Agreement);

- Any future Partnership distributions to limited partners require Lender approval;

- Calculation of the current ratio covenant was suspended until the reporting date of September 30, 2020;

- The definition of current ratio excludes the Affiliate Loan (discussed below) from the definition of liabilities; and

- As additional collateral for the loan, the Partnership established and funded a bank account with Lender in the amount of $1.6 million, to be used for interest payments under the Amended Loan Agreement until maturity (the balance of this collateral bank account at September 30, 2020 was approximately $1.3 million and is included in Restricted cash and cash equivalents on the Partnership’s September 30, 2020 consolidated balance sheet).

Also, under the Letter Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and natural gas sales. The risk management program must cover at least 80% of the Partnership’s projected total production of oil and natural gas for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021). See more information on the Partnership’s hedging program in Note 7. Risk Management.

In addition to the modification of certain terms under the Amended Loan Agreement, the Letter Agreement waived the defaults by the Partnership under the Amended Loan Agreement that existed prior to signing the Letter Agreement, including not meeting the current ratio covenant as of March 31, 2020, the Partnership not filing its first quarter financial statements within 60 days of March 31, 2020 and the non-payment by the Partnership of amounts due to Whiting. The Letter Agreement also waived the Partnership’s calculation of the current ratio covenant at June 30, 2020. The Letter Agreement also allows for the Affiliate Loan discussed below and payments under the Affiliate Loan.

In consideration for the modifications, amendments and waivers described above to the Amended Loan Agreement, the Letter Agreement provides for an amendment fee to Lender of $40,000, of which $15,000 was paid on September 30, 2020 and $25,000 is due December 31, 2020.

The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include:

● A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00

● A minimum ratio of current assets to current liabilities of 1.00 to 1.00 (“Current Ratio”)

● A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period

The Partnership was in compliance with its applicable covenants at September 30, 2020. If the Partnership is not in compliance with its covenants in future periods, it may not be able to obtain waivers and the outstanding balance under the Credit Facility may become due on demand at that time.

At September 30, 2020, the outstanding balance on the Credit Facility was $40 million, and the interest rate for the Credit Facility was 4.25%. As of September 30, 2020 and December 31, 2019, the outstanding balances on the Credit Facility were $40 million and $24 million, respectively, which approximate fair market value. The Partnership estimated the fair value of its Credit Facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

Term Loan from Affiliate

On July 21, 2020, the Partnership, as borrower, entered into a loan agreement with GKDML, LLC (“GKDML”), which provides for an unsecured, one-year term loan (“Term Loan” or “Affiliate Loan”) in the amount of $15 million. GKDML is owned and managed by Glade M. Knight and David S. McKenney, the Chief Executive Officer and the Chief Financial Officer, respectively, of the General Partner. The Term Loan bears interest at a variable rate based on LIBOR plus a margin of 2.00%, with a LIBOR floor of 0%. Interest is payable monthly. The Term Loan contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. At September 30, 2020, the outstanding balance on the Term Loan was $15 million, the interest rate for the Term Loan was approximately 2.2% and the Partnership was in compliance of all applicable covenants.

To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A. on July 21, 2020 (“GKDML Loan”). The GKDML Loan has substantially the same terms as the Term Loan and is personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and will not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimburse GKDML for all costs of the GKDML Loan. The Term Loan may be prepaid at any time with no penalty and in any amount, but any amounts repaid may not be reborrowed. 

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2020

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

Note 5. Asset Retirement Obligations

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows:

	2020		2019
Balance at January 1	$	1,452,734	$	1,294,067
Well additions		35,646		73,096
Accretion		61,547		52,482
Revisions		-		-
Balance at September 30	$	1,549,927	$	1,419,645

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Fair Value of Financial Instruments

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

Note 6. Fair Value of Financial Instruments

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

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

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

● Level 3: Significant unobservable inputs

The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the three and nine months ended September 30, 2020 and 2019, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2020 and December 31, 2019.

	Fair Value Measurements at September 30, 2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity derivatives - current assets	$	-	$	66,299	$	-
Total	$	-	$	66,299	$	-

	Fair Value Measurements at December 31, 2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(183,850	)	$	-
Total	$	-	$	(183,850	)	$	-

The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheet in Other current assets at September 30, 2020 and Accounts payable, accrued expenses and other current liabilities at December 31, 2019. See additional detail in Note 7. Risk Management.

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, oil, natural gas and natural gas liquids revenue 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.

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Risk Management

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

Note 7. Risk Management

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Periodically, the Partnership utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations. The Partnership settled three derivative contracts during the first quarter of 2020, and in accordance with the Letter Agreement discussed in Note 4. Debt, the Partnership is required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021). In August 2020, the Partnership established its risk management program by entering into costless collar derivative contracts for future oil and natural gas produced by the Sanish Field Assets during the period from August 2020 through February 2021. All derivative instruments are recorded on the Partnership’s balance sheet as assets or liabilities measured at fair value.

As of September 30, 2020, the Partnership’s derivative instruments with its counterparty were in a gain position; therefore, a current asset of approximately $66,000, which approximates its fair value, has been recognized as a derivative asset in Other current assets on the Partnership’s consolidated balance sheet as of September 30, 2020. As of December 31, 2019, the Partnership’s derivative instruments were in a loss position; therefore, a current liability of approximately $0.2 million, which approximates fair value, was recognized in Accounts payable, accrued expenses and other current liabilities on the Partnership’s consolidated balance sheet.

The Partnership determined the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performed an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considered that the counterparty is of substantial credit quality and had the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional discussion above in Note 6. Fair Value of Financial Instruments.

The Partnership has not designated its derivative instruments as hedges for accounting purposes and has not entered into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents settlements of matured derivative instruments and non-cash gains on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect realized gains on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash) gains below represent the change in fair value of derivative instruments which were held at period-end.

	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Settlements on matured derivatives	$	28,000	$	-	$	285,040	$	-
Gain on mark-to-market of derivatives		66,299		498,790		250,149		498,790
Gain on derivatives	$	94,299	$	498,790	$	535,189	$	498,790

The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars, and the contracts are settled monthly. The following table reflects the open costless collar derivative instruments as of September 30, 2020.

Settlement Period	Basis	Product	Volume	Floor / Ceiling Prices ($)	Fair Value of Asset / (Liability) at September 30, 2020
10/2020 - 02/2021	NYMEX	Oil (bbls)	75,000	37.50 / 44.50	$	24,000
10/2020 - 02/2021	NYMEX	Oil (bbls)	75,000	38.00 / 44.25	$	28,350
10/2020 - 02/2021	NYMEX	Oil (bbls)	75,000	38.00 / 44.00	$	22,500
10/2020 - 02/2021	NYMEX	Oil (bbls)	48,000	38.00 / 44.50	$	22,320
10/2020 - 02/2021	Henry Hub	Gas (MMBtu)	320,000	2.50 / 3.05	$	(30,871	)
					$	66,299

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

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Capital Contribution and Partners' Equity

9 Months Ended

Sep. 30, 2020

Partners' Capital Notes [Abstract]

Partners' Capital Notes Disclosure [Text Block]

Note 8. Capital Contribution and Partners’ Equity

At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, and the General Partner received Incentive Distribution Rights (defined below).

The Partnership completed its best-efforts offering of common units on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership had completed the sale of approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offerings costs of $349.6 million.

Under the agreement with David Lerner Associates, Inc. (the “Dealer Manager”), the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold through the best-efforts offering, the total contingent fee is a maximum of approximately $15.0 million.

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

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

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

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

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

In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to recent market volatility and the impact on the Partnership’s operating cash flows. The Partnership will accumulate unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs, as defined above. As of September 30, 2020, the unpaid Payout Accrual totaled $0.828493 per common unit, or approximately $16 million. As discussed in Note 4. Debt and pursuant to the Letter Agreement, the Partnership is not permitted to pay distributions without lender approval.

For the nine months ended September 30, 2020, the Partnership paid distributions of $0.241644, or $4.6 million. For the three and nine months ended September 30, 2019, the Partnership paid distributions of $0.349041 and $1.047123 per common unit, or $6.6 million and $19.9 million, respectively.

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Related Parties

9 Months Ended

Sep. 30, 2020

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

Note 9. Related Parties

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

As described in Note 4. Debt, in July 2020, the Partnership entered into a loan agreement with GKDML, which provided for a $15 million unsecured, one-year Term Loan. GKDML is owned and managed by Messrs. Knight and McKenney, the Chief Executive Officer and the Chief Financial Officer, respectively, of the General Partner. To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A., which has substantially the same terms as the Term Loan and is personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and will not receive any consideration for providing the Term Loan or the guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimburse GKDML for all costs of its loan with Bank of America.

For the three and nine months ended September 30, 2020, approximately $101,000 and $291,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At September 30, 2020, approximately $101,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets. For the three and nine months ended September 30, 2019, approximately $88,000 and $236,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership.

The members of the General Partner are affiliates of Mr. Knight, Mr. McKenney, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Messrs. Knight and McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. On January 31, 2018, the Partnership entered into a cost sharing agreement with ER12 that gives ER12 access to the Partnership’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The shared day-to-day costs are split evenly between the two partnerships and any direct third-party costs are paid by the party receiving the services. The shared costs are based on actual costs incurred with no mark-up or profit to the Partnership. The agreement may be terminated at any time by either party upon 60 days written notice.

The Partnership leases office space in Oklahoma City, Oklahoma on a month-to-month basis from an affiliate of the General Partner. For the three and six months ended June 30, 2020 and 2019, the Partnership paid $25,611 and $51,222 in each period, respectively, to the affiliate of the General Partner. The office space is shared between the Partnership and ER12; therefore, under the cost-sharing agreement, the monthly payment of $8,537 is split between the two partnerships. In addition to the office space, the cost-sharing agreement reduces the costs to the Partnership for accounting and asset management services provided through a member of the General Partner noted above. The compensation due to Clifford J. Merritt, President of the General Partner, is also a shared cost between the Partnership and ER12. For the three and nine months ended September 30, 2020, approximately $64,000 and $204,000, respectively, of expenses subject to the cost-sharing agreement were paid by the Partnership and have been or will be reimbursed by ER12. At September 30, 2020, the approximately $64,000 due to the Partnership from ER12 is included in Other current assets in the consolidated balance sheets. For the three and nine months ended September 30, 2019, approximately $65,000 and $200,000, respectively, of expenses subject to the cost sharing agreement were paid by the Partnership and have been reimbursed by ER12.

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Subsequent Events

9 Months Ended

Sep. 30, 2020

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Note 10. Subsequent Events

In October 2020, ER12 provided 60-day written notice to the Partnership of ER12’s intention to terminate the cost sharing agreement between the Partnership and ER12. The cost sharing agreement will terminate on December 31, 2020.

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Accounting Policies, by Policy (Policies)

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

Basis of Presentation

The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements included in its 2019 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2020 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2020.

Use of Estimates, Policy [Policy Text Block]

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.

Revenue [Policy Text Block]

Revenue Recognition

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

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

Earnings Per Share, Policy [Policy Text Block]

Net Income (Loss) Per Common Unit

Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (loss) per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and nine months ended September 30, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.

New Accounting Pronouncements, Policy [Policy Text Block]

Recently Adopted Accounting Standards

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848), which provides optional guidance through December 31, 2022 to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments in ASU No. 2020-04 apply to contract modifications that replace a reference rate affected by reference rate reform, providing optional expedients regarding the measurement of hedge effectiveness in hedging relationships that have been modified to replace a reference rate. While the guidance in ASU No. 2020-04 became effective upon issuance, the provisions of the ASU did not have a material impact on the Partnership’s consolidated financial statements and related disclosures as of September 30, 2020.

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2020

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations [Table Text Block]

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows:

	2020		2019
Balance at January 1	$	1,452,734	$	1,294,067
Well additions		35,646		73,096
Accretion		61,547		52,482
Revisions		-		-
Balance at September 30	$	1,549,927	$	1,419,645

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Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2020

Fair Value Disclosures [Abstract]

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

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2020 and December 31, 2019.

	Fair Value Measurements at September 30, 2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity derivatives - current assets	$	-	$	66,299	$	-
Total	$	-	$	66,299	$	-

	Fair Value Measurements at December 31, 2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(183,850	)	$	-
Total	$	-	$	(183,850	)	$	-

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Risk Management (Tables)

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

The Partnership has not designated its derivative instruments as hedges for accounting purposes and has not entered into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents settlements of matured derivative instruments and non-cash gains on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect realized gains on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash) gains below represent the change in fair value of derivative instruments which were held at period-end.

	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Settlements on matured derivatives	$	28,000	$	-	$	285,040	$	-
Gain on mark-to-market of derivatives		66,299		498,790		250,149		498,790
Gain on derivatives	$	94,299	$	498,790	$	535,189	$	498,790

Schedule of Derivative Instruments [Table Text Block]

The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars, and the contracts are settled monthly. The following table reflects the open costless collar derivative instruments as of September 30, 2020.

Settlement Period	Basis	Product	Volume	Floor / Ceiling Prices ($)	Fair Value of Asset / (Liability) at September 30, 2020
10/2020 - 02/2021	NYMEX	Oil (bbls)	75,000	37.50 / 44.50	$	24,000
10/2020 - 02/2021	NYMEX	Oil (bbls)	75,000	38.00 / 44.25	$	28,350
10/2020 - 02/2021	NYMEX	Oil (bbls)	75,000	38.00 / 44.00	$	22,500
10/2020 - 02/2021	NYMEX	Oil (bbls)	48,000	38.00 / 44.50	$	22,320
10/2020 - 02/2021	Henry Hub	Gas (MMBtu)	320,000	2.50 / 3.05	$	(30,871	)
					$	66,299

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Partnership Organization (Details) shares in Millions		1 Months Ended		9 Months Ended	12 Months Ended	21 Months Ended	27 Months Ended	46 Months Ended
	Jul. 09, 2013 USD ($)	Oct. 31, 2020 USD ($)	Jul. 31, 2020 USD ($)	Sep. 30, 2020 USD ($)	Dec. 31, 2019	Sep. 30, 2020 USD ($)	Dec. 31, 2019 USD ($)	Apr. 24, 2017 USD ($) shares	Jun. 30, 2020 USD ($)	Nov. 21, 2017 USD ($)
Partnership Organization (Details) [Line Items]
Limited Liability Company or Limited Partnership, Business, Formation State	Delaware
Partners' Capital Account, Contributions	$ 1,000
Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Capital Expenditures, Drilling and Completion of Wells				$ 63,000,000			$ 7,800,000
Costs Incurred, Development Costs				$ 42,000,000
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net				25.00%
Oil, Productive Well, Number of Wells, Net				243		243
Non-operated Wells in the Process of Drilling [Member]
Partnership Organization (Details) [Line Items]
Oil and Gas, Present Activity, Well in Process of Drilling				21		21
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net				18.00%
Oil and Gas, Present Activity, Well in Process of Drilling				21		21
Whiting Petroleum [Member]
Partnership Organization (Details) [Line Items]
Amounts Outstanding to Operator			$ 19,000,000						$ 20,000,000
Debt Instrument, Term			1 year
Subsequent Event [Member]
Partnership Organization (Details) [Line Items]
Repayments of Related Party Debt		$ 5,000,000
Debt, Current		$ 50,000,000
Revolving Credit Facility [Member]
Partnership Organization (Details) [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity				$ 40,000,000		$ 40,000,000
Debt Instrument, Face Amount										$ 20,000,000
Best-Efforts Offering [Member]
Partnership Organization (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares) | shares								19.0
Proceeds from Issuance of Common Limited Partners Units								$ 374,200,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units								$ 349,600,000
GKDML [Member]
Partnership Organization (Details) [Line Items]
Debt Instrument, Term			1 year
Debt Instrument, Face Amount			$ 15,000,000
Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Wells Elected to Participate in Drilling					43	43
Capital Expenditures, Drilling and Completion of Wells						$ 63,000,000
Costs Incurred, Development Costs						$ 42,000,000

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Summary of Significant Accounting Policies (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Accounting Policies [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	0	0	0

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Oil and Natural Gas Investments (Details) $ in Millions				1 Months Ended	9 Months Ended	12 Months Ended		21 Months Ended	27 Months Ended
	Mar. 31, 2017	Jan. 11, 2017 USD ($)	Dec. 18, 2015 USD ($)	Mar. 31, 2017 USD ($)	Sep. 30, 2020 USD ($)	Dec. 31, 2019	Dec. 31, 2018	Sep. 30, 2020 USD ($)	Dec. 31, 2019 USD ($)
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number							6
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 63.0				$ 7.8
Costs Incurred, Development Costs (in Dollars)					42.0
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					1.0
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 2.0
Acquisition No. 1 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			11.00%
Business Combination, Consideration Transferred (in Dollars)			$ 159.6
Acquisition No. 2 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net		11.00%
Business Combination, Consideration Transferred (in Dollars)		$ 128.5
Acquisition No. 3 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net	10.50%
Business Combination, Consideration Transferred (in Dollars)				$ 52.4
Number of Producing Partnership Wells Acquired	82
Oil, Productive Well, Number of Wells, Net	216			216
Number of Future Development Partnership Locations Acquired	150
Gas and Oil Area Undeveloped, Net	253
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)								$ 63.0
Wells Elected to Participate in Drilling						43		43
Costs Incurred, Development Costs (in Dollars)								$ 42.0
Whiting Petroleum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number							2
Whiting Petroleum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number							2
Working Interest							29.00%
Oasis Petroleum, Inc. [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number							4
Working Interest							8.00%
Non-operated Completed Wells [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number								22
Working Interest					23.00%			23.00%
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net					25.00%
Oil, Productive Well, Number of Wells, Net					243			243
Non-operated Wells in the Process of Drilling [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Working Interest					18.00%			18.00%
Oil and Gas, Present Activity, Well in Process of Drilling					21			21
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net					18.00%
Oil and Gas, Present Activity, Well in Process of Drilling					21			21

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Debt (Details) - USD ($)				1 Months Ended	9 Months Ended
	Jul. 21, 2020	Sep. 30, 2019	Nov. 21, 2017	Jul. 31, 2020	Sep. 30, 2020	Dec. 31, 2019
Debt (Details) [Line Items]
Long-term Line of Credit					$ 0	$ 24,000,000
Line of Credit Facility, Fair Value of Amount Outstanding					40,000,000	24,000,000
Notes Payable, Related Parties, Current					$ 15,000,000	$ 0
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount			$ 20,000,000
Debt Instrument, Maturity Date			Nov. 21, 2019
Line of Credit Facility, Commitment Fee Description		the Partnership paid an origination fee of 0.45% on the change in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000
Line of Credit Facility, Commitment Fee Percentage		0.45%
Line of Credit Facility, Commitment Fee Amount		$ 90,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.50%
Line of Credit Facility, Covenant Terms		The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include:     ● A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00   ● A minimum ratio of current assets to current liabilities of 1.00 to 1.00 (“Current Ratio”)   ● A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period
Line of Credit Facility, Covenant Compliance					The Partnership was in compliance with its applicable covenants at September 30, 2020
Long-term Line of Credit					$ 40,000,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate					4.25%
Revolving Credit Facility [Member] | Amended Loan Agreement [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount		$ 40,000,000
Debt Instrument, Maturity Date	Sep. 30, 2022	Sep. 30, 2022
Line of Credit Facility, Borrowing Capacity, Description		an increase to the borrowing base from $30 million to an initially stipulated $40 million
Line of Credit Facility, Collateral		an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties
Credit Facility, Letter Agreement	On July 21, 2020, the Partnership entered into a letter agreement (“Letter Agreement”) with Lender that amended and modified the Amended Loan Agreement. The modifications to the Amended Loan Agreement include, among other items, the following:    - Maturity date was changed from September 30, 2022 to July 31, 2021;   - Interest rate was changed to the prime rate plus 1.00%, with an interest rate floor of 4.00% (an increase of 50 basis points from the rate prior to the Letter Agreement);   - Any future Partnership distributions to limited partners require Lender approval;   - Calculation of the current ratio covenant was suspended until the reporting date of September 30, 2020;   - The definition of current ratio excludes the Affiliate Loan (discussed below) from the definition of liabilities; and   - As additional collateral for the loan, the Partnership established and funded a bank account with Lender in the amount of $1.6 million, to be used for interest payments under the Amended Loan Agreement until maturity (the balance of this collateral bank account at September 30, 2020 was approximately $1.3 million and is included in Restricted cash and cash equivalents on the Partnership’s September 30, 2020 consolidated balance sheet).
Debt Instrument, Collateral Amount	$ 1,600,000
Restricted Cash, Current					$ 1,300,000
Debt, Risk Management, Description	Also, under the Letter Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and natural gas sales. The risk management program must cover at least 80% of the Partnership’s projected total production of oil and natural gas for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021)
Debt Instrument, Fee Amount	$ 40,000
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Amended Loan Agreement [Member] | Minimum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.50%
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Amended Loan Agreement [Member] | Maximum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate		3.50%
Revolving Credit Facility [Member] | Prime Rate [Member] | Amended Loan Agreement [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Revolving Credit Facility [Member] | Prime Rate [Member] | Amended Loan Agreement [Member] | Minimum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	4.00%
Revolving Credit Facility [Member] | Amendment Fee, Due September 30, 2020 [Member] | Amended Loan Agreement [Member]
Debt (Details) [Line Items]
Debt Instrument, Fee Amount	$ 15,000
Revolving Credit Facility [Member] | Amendment Fee, Due December 31, 2020 [Member] | Amended Loan Agreement [Member]
Debt (Details) [Line Items]
Debt Instrument, Fee Amount	$ 25,000
GKDML [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount				$ 15,000,000
Debt Instrument, Term				1 year
Notes Payable, Related Parties, Current					$ 15,000,000
Short-term Debt, Weighted Average Interest Rate, at Point in Time					2.20%
GKDML [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate				2.00%
GKDML [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate				0.00%

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Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations - USD ($)	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Schedule of Asset Retirement Obligations [Abstract]
Balance	$ 1,452,734	$ 1,294,067
Well additions	35,646	73,096
Accretion	61,547	52,482
Revisions	0	0
Balance	$ 1,549,927	$ 1,419,645

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Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis - USD ($)	Sep. 30, 2020	Dec. 31, 2019
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current assets	$ 0
Total	0
Commodity derivatives - current liabilities		$ 0
Total		0
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current assets	66,299
Total	66,299
Commodity derivatives - current liabilities		(183,850)
Total		(183,850)
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current assets	0
Total	$ 0
Commodity derivatives - current liabilities		0
Total		$ 0

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Risk Management (Details)	9 Months Ended
	Sep. 30, 2020 USD ($)	Dec. 31, 2019 USD ($)
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Discussion of Price Risk Derivative Risk Management Policy	The Partnership settled three derivative contracts during the first quarter of 2020, and in accordance with the Letter Agreement discussed in Note 4. Debt, the Partnership is required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021).
Number of Price Risk Derivatives Held	3
Derivative Asset, Current	$ 66,000
Derivative Liability, Current		$ 200,000

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Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - Price Risk Derivative [Member] - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivatives, Fair Value [Line Items]
Settlements on matured derivatives	$ 28,000	$ 0	$ 285,040	$ 0
Gain on mark-to-market of derivatives	66,299	498,790	250,149	498,790
Gain on derivatives	$ 94,299	$ 498,790	$ 535,189	$ 498,790

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Risk Management (Details) - Schedule of Derivative Instruments	9 Months Ended
	Sep. 30, 2020 USD ($) $ / item bbl
Derivative [Line Items]
Fair Value of Asset / (Liability) | $	$ 66,299
Costless Collar Agreements #1 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	75,000
Floor Prices	37.50
Ceiling Prices	44.50
Fair Value of Asset / (Liability) | $	$ 24,000
Costless Collar Agreements #2 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	75,000
Floor Prices	38.00
Ceiling Prices	44.25
Fair Value of Asset / (Liability) | $	$ 28,350
Costless Collar Agreements #3 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	75,000
Floor Prices	38.00
Ceiling Prices	44.00
Fair Value of Asset / (Liability) | $	$ 22,500
Costless Collar Agreements #4 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	48,000
Floor Prices	38.00
Ceiling Prices	44.50
Fair Value of Asset / (Liability) | $	$ 22,320
Costless Collar Agreements #5 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	Henry Hub
Product	Gas (MMBtu)
Volume | bbl	320,000
Floor Prices	2.50
Ceiling Prices	3.05
Fair Value of Asset / (Liability) | $	$ (30,871)

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Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions		3 Months Ended				9 Months Ended		46 Months Ended
	Jul. 09, 2013	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019	Apr. 24, 2017
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Contributions	$ 1,000
Distributions to organizational limited partner	$ 990
Partners' Capital Account, Description of Units Sold						Under the agreement with David Lerner Associates, Inc. (the “Dealer Manager”), the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership.
Managing Dealer, Selling Commissions, Percentage						6.00%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds, Percentage						4.00%
Maximum Contingent Offering Costs, Selling Commissions and Marketing Expenses						$ 15,000,000.0
Key Provisions of Operating or Partnership Agreement, Description						The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per unit, regardless of the amount paid for the unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount. All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:  ● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;   ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).
Annualized Rate of Retun					7.00%
Distribution at Payout to limited partner, per common unit (in Dollars per share)						$ 0.828493
Distribution at Payout to limited partner						$ 16,000,000
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)			$ 0.349041			$ 0.241644	$ 1.047123
Distribution Made to Limited Partner, Cash Distributions Paid		$ 4,584,826	$ 6,622,520	$ 6,622,521	$ 6,622,520	$ 4,584,826	$ 19,867,561
Best-Efforts Offering [Member]
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares)								19.0
Proceeds from Issuance of Common Limited Partners Units								$ 374,200,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units								$ 349,600,000

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Related Parties (Details) - USD ($)	1 Months Ended	3 Months Ended			6 Months Ended	9 Months Ended
	Jul. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Sep. 30, 2019	Jun. 30, 2020	Sep. 30, 2020	Sep. 30, 2019
GKDML [Member]
Related Parties (Details) [Line Items]
Debt Instrument, Face Amount	$ 15,000,000
Debt Instrument, Term	1 year
General Partner [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		$ 101,000		$ 88,000		$ 291,000	$ 236,000
Due to Related Parties, Current		101,000				101,000
Affiliated Entity [Member]
Related Parties (Details) [Line Items]
Operating Leases, Rent Expense			$ 25,611		$ 51,222
Operating Leases, Rent Expense, Minimum Rentals					$ 8,537
Reimbursements From Related Party		64,000		$ 65,000		204,000	$ 200,000
Due from Related Parties		$ 64,000				$ 64,000