Energy 11 10-Q 2020 Q1 Quarterly report

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 March 31, 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 June 22, 2020, the Partnership had 18,973,474 common units outstanding.

EXPLANATORY NOTE

As previously disclosed in the Current Report on Form 8-K filed by Energy 11, L.P. (the “Partnership”) with the Securities and Exchange Commission (the “SEC”) on May 13, 2020, the Partnership relied on the SEC’s Order Under Section 36 of the Securities Exchange Act of 1934 Modifying Exemptions From the Reporting and Proxy Delivery Requirements for Public Companies, dated March 25, 2020 (Release No. 34-88465), to delay the filing of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 (the “Form 10-Q”) due to circumstances related to COVID-19. The need to address the immediate and evolving impacts of COVID-19 on the Partnership’s business and operations, including impacts to its oil and natural gas properties in North Dakota, increased the demands on the Partnership’s personnel at a time when stay-at-home orders, including in Oklahoma, Texas and Virginia, where the Partnership’s personnel are located, impacted normal working patterns. This slowed the Partnership’s normal quarterly close and financial reporting processes related to its Form 10-Q.

Energy 11, L.P.

Form 10-Q

Index

			Page Number
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements (Unaudited)
		Consolidated Balance Sheets – March 31, 2020 and December 31, 2019	3
		Consolidated Statements of Operations – Three months ended March 31, 2020 and 2019	4
		Consolidated Statements of Partners’ Equity – Three months ended March 31, 2020 and 2019	5
		Consolidated Statements of Cash Flows – Three months ended March 31, 2020 and 2019	6
		Notes to Consolidated Financial Statements	7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23
	Item 4.	Controls and Procedures	23
PART II. OTHER INFORMATION
	Item 1.	Legal Proceedings	24
	Item 1A.	Risk Factors	24
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	25
	Item 3.	Defaults upon Senior Securities	25
	Item 4.	Mine Safety Disclosures	26
	Item 5.	Other Information	26
	Item 6.	Exhibits	26
Signatures			27

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Energy 11, L.P.

Consolidated Balance Sheets

	March 31,			December 31,
	2020			2019
	(unaudited)
Assets
Cash and cash equivalents	$	2,709,116		$	348,550
Oil, natural gas and natural gas liquids revenue receivable		9,288,131			5,857,926
Other current assets		221,726			284,652
Total Current Assets		12,218,973			6,491,128
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $57,731,046 and $53,186,165, respectively		337,656,904			326,758,636
Total Assets	$	349,875,877		$	333,249,764
Liabilities
Revolving credit facility	$	40,000,000		$	-
Accounts payable, accrued expenses and other current liabilities		22,290,748			20,061,059
Total Current Liabilities		62,290,748			20,061,059
Revolving credit facility		-			24,000,000
Asset retirement obligations		1,500,557			1,452,734
Total Liabilities		63,791,305			45,513,793
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)		286,086,299			287,737,698
General partner's interest		(1,727	)		(1,727	)
Class B Units (62,500 units issued and outstanding, respectively)		-			-
Total Partners’ Equity		286,084,572			287,735,971
Total Liabilities and Partners’ Equity	$	349,875,877		$	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
	March 31, 2020			March 31, 2019
Revenues
Oil	$	10,229,733		$	8,092,070
Natural gas		354,574			961,112
Natural gas liquids		519,227			1,038,163
Total revenue		11,103,534			10,091,345
Operating costs and expenses
Production expenses		2,052,237			2,818,717
Production taxes		992,341			810,793
General and administrative expenses		565,297			494,482
Depreciation, depletion, amortization and accretion		4,564,861			3,433,551
Total operating costs and expenses		8,174,736			7,557,543
Operating income		2,928,798			2,533,802
Gain on derivatives		440,890			-
Interest expense, net		(436,261	)		(193,828	)
Total other expense, net		4,629			(193,828	)
Net income	$	2,933,427		$	2,339,974
Basic and diluted net income per common unit	$	0.15		$	0.12
Weighted average common units outstanding - basic and diluted		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
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

See notes to consolidated financial statements.

5

Energy 11, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended			Three Months Ended
	March 31, 2020			March 31, 2019
Cash flow from operating activities:
Net income	$	2,933,427		$	2,339,974
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion		4,564,861			3,433,551
Gain on mark-to-market of derivatives		(183,850	)		-
Non-cash expenses, net		10,164			11,198
Changes in operating assets and liabilities:
Oil, natural gas and natural gas liquids revenue receivable		(3,430,205	)		599,643
Other current assets		52,762			54,224
Accounts payable, accrued expenses and other current liabilities		289,117			(723,746	)
Net cash flow provided by operating activities		4,236,276			5,714,844
Cash flow from investing activities:
Additions to oil and natural gas properties		(13,290,884	)		(235,449	)
Net cash flow used in investing activities		(13,290,884	)		(235,449	)
Cash flow from financing activities:
Proceeds from revolving credit facility		16,000,000			-
Distributions paid to limited partners		(4,584,826	)		(6,622,520	)
Net cash flow provided by (used in) financing activities		11,415,174			(6,622,520	)
Increase (decrease) in cash and cash equivalents		2,360,566			(1,143,125	)
Cash and cash equivalents, beginning of period		348,550			3,685,327
Cash and cash equivalents, end of period	$	2,709,116		$	2,542,202
Interest paid	$	441,591		$	190,642
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$	20,547,754		$	20,972

See notes to consolidated financial statements.

6

Energy 11, L.P.

Notes to Consolidated Financial Statements

March 31, 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 March 31, 2020, the Partnership owned an approximate 25% non-operated working interest in 235 currently producing wells, an estimated approximate 20% non-operated working interest in 26 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, the Partnership elected to participate in the drilling of 33 new wells at an estimated total investment cost to the Partnership of approximately $52 million. In the first quarter of 2020, the Partnership elected to participate in the drilling of an additional 10 new wells at an estimated total investment cost to the Partnership of approximately $13 million, for a total of 43 new wells at an estimated cost to the Partnership of approximately $65 million. In conjunction with this drilling program performed primarily by Whiting, the Partnership has incurred approximately $39 million in capital expenditures through March 31, 2020. 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. During the fourth quarter of 2019 and into the first quarter of 2020, the Partnership primarily used availability under its $40 million revolving credit facility (“Credit Facility”, described in Note 4. Debt) to fund its capital expenditure requirements. As of March 31, 2020, the Partnership did not have any availability under its Credit Facility and has not been successful in securing additional financing.

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 include 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 demand for oil and natural gas is anticipated to be low for the remainder of 2020. 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, and there is uncertainty as to when oil prices may stabilize at more economical levels for producers. With the anticipation that worldwide oil and natural gas prices will remain depressed during the remainder of 2020, operators within the United States have altered drilling programs and reduced forecasted capital expenditures. Further, because reduced demand and excess supply has strained storage facilities, operators may not be able to sell produced oil and natural gas at an economical price point. Operators may be forced to curtail production, shut-in producing wells or seek other cost-cutting measures until commodity prices increase. These factors are expected to have a significant adverse impact on the Partnership’s business and its financial condition.

7

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 suspended its Sanish field drilling program during the second quarter of 2020. As of March 31, 2020, the Partnership had approximately $21 million in accrued capital expenditures due to Whiting, and the Partnership estimates it may incur approximately $5 to $7 million in additional capital expenditures during the second quarter of 2020 based upon the status of the in-process wells when Whiting suspended its drilling program. As a result of the depressed commodity prices caused by the economic conditions and anticipated reduced production discussed above, in conjunction with having no current additional capital resources other than cash flow from operations, the Partnership may not be able to timely meet its obligations to Whiting as they come due. Currently, Whiting is offsetting Partnership revenue earned against Partnership amounts due to Whiting, which allows the Partnership to pay down its obligations to Whiting through cash flow from operations over time, but also fund its debt service and other working capital requirements as the Partnership works to pursue additional capital resources. The Partnership can offer no assurance that Whiting will not pursue other remedies allowable under the joint operating agreements between Whiting, as operator, and the Partnership, as a working interest owner, including foreclosure on the Partnership’s working and revenue interests on certain wells, which would affect the future revenues, operating expenses, reserve volumes and potential impairment reported by the Partnership.

The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) its lender group providing waivers to certain covenants and the Partnership’s ability to comply with other obligations under its loan agreement (see Note 4. Debt for further discussion); (ii) reaching an agreement with Whiting to resolve the Partnership’s obligations to Whiting; (iii) securing additional capital; (iv) 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 (v) 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. Further, 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. Since the Partnership has not fully and effectively implemented all of its plans detailed above and if the outstanding balance of the Credit Facility is accelerated and becomes immediately due and payable, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy the obligations that create 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 months ended March 31, 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.

8

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. 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 Per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were 0 common units with a dilutive effect for the three months ended March 31, 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 7) 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 March 31, 2020.

Note 3. Oil and Natural Gas Investments

On December 18, 2015, the Partnership completed its first purchase (“Acquisition No. 1”) 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 (“Acquisition No. 2”) 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 (“Acquisition No. 3”) 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, 6 wells were completed by the Partnership’s operators. NaN wells were completed by and are being operated by Whiting; the Partnership has an approximate 29% non-operated working interest in these 2 wells. The other 4 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. NaN (14) of these 43 wells have been completed and were producing at March 31, 2020; the Partnership has an approximate non-operated working interest of 22% in these 14 wells. The Partnership has an estimated approximate non-operated working interest of 20% in 26 wells that are in-process as of March 31, 2020. Drilling had not commenced on the remaining 3 wells as of March 31, 2020; the Partnership has an approximate non-operated working interest of 19% in these three wells. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 43 wells is approximately $65 million, of which approximately $39 million was incurred as of March 31, 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 will incur approximately $5 to $7 million in additional capital expenditures during the second quarter of 2020 based upon the status of these wells upon suspension of Whiting’s drilling program. However, it is difficult to predict the amount and timing of capital expenditures, and 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, commodity price decreases and the oversupply of oil in the United States during the first quarter of 2020 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 April 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 costs 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 March 31, 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

On November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”), 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”), which provides 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 are generally similar to the Partnership’s existing revolving credit facility and include 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 March 31, 2020, the outstanding balance on the Credit Facility was $40 million, and the interest rate for the Credit Facility was approximately 4.4%.

At closing 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.

The Amended Loan Agreement requires the Partnership to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer. If this condition is met, the risk management program must cover at least 50% of the Partnership’s projected total production of oil and natural gas for a rolling 18-month period. At December 31, 2019, the Partnership’s borrowing base of $40 million did not exceed 50% of its estimated producing reserves, and the Partnership’s reserves are next subjected to redetermination at June 30, 2020. Therefore, as of March 31, 2020, the Partnership is not required to maintain a risk management program. The Amended Loan Agreement does permit the Partnership to enter into derivative contracts with a counterparty at its own discretion so long as the term does not exceed 36 months and does not cover more than 80% of the Partnership’s projected oil and gas volumes.

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

● Partnership distributions may be limited if certain terms and conditions are not met; these limitations include (i) being limited to 50% of the previous quarter EBITDAX beginning April 1, 2020 or (ii) having distributions reduced to zero if the availability under the Revolver Commitment Amount is less than 20% of the Revolver Commitment Amount.

10

The Partnership was in compliance with each of the covenants, except the Current Ratio covenant, at March 31, 2020. As a result of not being in compliance with the Current Ratio covenant, the Partnership notified the lender group of the Credit Facility and expects to enter into a waiver agreement with the lender group that would waive compliance with the Current Ratio covenant until the calculation is due as of September 30, 2020. The terms of the waiver agreement are anticipated to include, among other items, a restriction on the Partnership’s ability to make distributions until approved by the lender group. The Partnership anticipates, based on the current operating environment, it may not be able to meet the Current Ratio covenant at September 30, 2020. If the Partnership cannot meet the Current Ratio covenant or any other covenant 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. Because the Partnership has not entered into a waiver agreement as of the date of this Form 10-Q filing and as a result of the anticipated future failure to meet the Current Ratio covenant at September 30, 2020, the Partnership reclassified the outstanding balance due under the Credit Facility to current on its March 31, 2020 consolidated balance sheet.

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. As of March 31, 2020, the carrying value and estimated fair value of the Partnership’s outstanding debt were approximately $40 million and $33 million, respectively. As of December 31, 2019, both the carrying value and estimated fair value of the Partnership’s outstanding debt were $24 million.

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s 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 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		27,844		-
Accretion		19,979		17,964
Revisions		-		-
Balance at March 31	$	1,500,557	$	1,312,031

Note 6. Risk Management

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. 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. All derivative instruments are recorded on the Partnership’s balance sheet as assets or liabilities measured at fair value. As discussed in Note 4. Debt, the Partnership will be required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer.

At December 31, 2019, the Partnership had 3 outstanding monthly costless collar derivative contracts, which hedged a total of 82,000 barrels of first quarter 2020 oil production. The Partnership settled these monthly derivative contracts during the first quarter of 2020 at a gain of approximately $257,000. The Partnership also recorded a non-cash gain during the first quarter of 2020, which represents the reversal of the $184,000 derivative liability recorded at December 31, 2019 on the Partnership’s consolidated balance sheet.

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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 did not qualify or were not designated as a hedge, the changes in the fair value were recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The Partnership had no outstanding contracts at March 31, 2020. The following table presents the Partnership’s gain at settlement of its matured derivative instruments and the non-cash gain the Partnership recorded during the three months ended March 31, 2020.

	Three Months Ended March 31, 2020
Settlements on matured derivatives	$	257,040
Gain on mark-to-market of derivatives		183,850
Gain on derivatives	$	440,890

Note 7. Capital Contribution and Partners’ Equity

At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, 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%).

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For the three months ended March 31, 2020 and 2019, the Partnership paid distributions of $0.241644 and $0.349041 per common unit, or $4.6 million and $6.6 million, respectively. 

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 March 31, 2020, the unpaid Payout Accrual totaled $0.107397 per common unit, or approximately $2.0 million. The General Partner will continue to monitor the Partnership’s distribution policy on a monthly basis in conjunction with the Partnership’s projected cash requirements for operations, capital expenditures for new wells, debt service and any restrictions under its Credit Facility. As discussed in Note 4. Debt and pursuant to the anticipated waiver to be granted by the Partnership’s lending group, the Partnership will not be permitted to pay distributions without lender approval.

Note 8. 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.

For the three months ended March 31, 2020 and 2019, approximately $92,000 and $68,000 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 March 31, 2020, approximately $92,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets.

The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer, David S. McKenney, Chief Financial Officer, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Mr. Knight and Mr. McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and 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 months ended March 31, 2020 and 2019, the Partnership paid $25,611 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 months ended March 31, 2020 and 2019, approximately $76,000 and $65,000, respectively, of expenses subject to the cost-sharing agreement were paid by the Partnership and have been or will be reimbursed by ER12. At March 31, 2020, the approximately $76,000 due to the Partnership from ER12 is included in Other current assets in the consolidated balance sheets.

Note 9. Subsequent Events

On April 1, 2020, 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. Whiting has indicated its business will operate in the normal course without material disruption to its vendors, partners or employees, including the Partnership. At this time, the Partnership is unable to estimate the impact this will have on its operating results, if any.

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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 current financial obligations, including amounts due to its primary operator;

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

● 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.

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.

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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 March 31, 2020, the Partnership owned an approximate 25% non-operated working interest in 235 currently producing wells, an estimated approximate 20% non-operated working interest in 26 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 (“Acquisition No. 1”) 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 (“Acquisition No. 2”) 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 (“Acquisition No. 3”) 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. Fourteen (14) of these 43 wells have been completed and were producing at March 31, 2020; the Partnership has an approximate non-operated working interest of 22% in these 14 wells. The Partnership has an estimated approximate non-operated working interest of 20% in 26 wells that are in-process as of March 31, 2020. Drilling had not commenced on the remaining three wells as of March 31, 2020; the Partnership has an approximate non-operated working interest of 19% in these three wells. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 43 wells is approximately $65 million, of which approximately $39 million was incurred as of March 31, 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

As described above, during 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling of a total of 43 new wells. The estimated cost to the Partnership for the new wells is approximately $65 million. In conjunction with this drilling program (primarily performed by Whiting), the Partnership has incurred approximately $39 million in capital expenditures through March 31, 2020. 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. During the fourth quarter of 2019 and into the first quarter of 2020, the Partnership primarily used availability under its $40 million revolving credit facility (“Credit Facility”, described in “Note 4. Debt” in Part I, Item 1 of this Form 10-Q”) to fund its capital expenditure requirements. As of March 31, 2020, the Partnership does not have any availability under its Credit Facility and has not been successful in securing additional financing.

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Subsequent to the Partnership’s election to participate in Whiting’s drilling program, several factors, described in “Current Price Environment” below, have had a significant 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 suspended its Sanish field drilling program during the second quarter of 2020. As of March 31, 2020, the Partnership had approximately $21 million in accrued capital expenditures due to Whiting, and the Partnership estimates it will incur approximately $5 to $7 million in additional capital expenditures during the second quarter of 2020 based upon the status of the in-process wells when Whiting suspended its drilling program. As a result of the depressed commodity prices caused by the economic conditions and anticipated reduced production discussed below, in conjunction with having no current additional capital resources other than cash flow from operations, the Partnership may not be able to timely meet its obligations to Whiting as they come due. Currently, Whiting is offsetting Partnership revenue earned against Partnership amounts due to Whiting, which allows the Partnership to pay down its obligations to Whiting through cash flow from operations over time, but also fund its debt service and other working capital requirements as the Partnership works to pursue additional capital resources. The Partnership can offer no assurance that Whiting will not pursue other remedies allowable under the joint operating agreements between Whiting, as operator, and the Partnership, as a working interest owner, including foreclosure on the Partnership’s working and revenue interests on certain wells, which would affect the future revenues, operating expenses, reserve volumes and potential impairment reported by the Partnership.

The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) its lender group providing waivers to certain covenants and the Partnership’s ability to comply with other obligations under its loan agreement (see “Note 4. Debt” in Part I, Item 1 of this Form 10-Q for further discussion); (ii) reaching an agreement with Whiting to resolve the Partnership’s obligations to Whiting; (iii) securing additional capital; (iv) 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 (v) 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. Further, 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. Since the Partnership has not fully and effectively implemented all of its plans detailed above and if the outstanding balance of the Credit Facility is accelerated and becomes immediately due and payable, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy the obligations that create 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 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. Because of COVID-19’s impact to the global economy, demand for fossil fuels substantially declined during the first quarter of 2020, and demand is anticipated to be low for the remainder of 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, excess crude oil and natural gas inventory and shrinking storage capacity 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. The average NYMEX futures closing prices for the months of March and April 2020 were $30.45 and $16.70, respectively. With the anticipation that worldwide oil and natural gas prices will remain depressed during the remainder of 2020, operators within the United States have altered drilling programs and reduced forecasted capital expenditures. Also, because reduced demand and excess supply have strained storage facilities, operators may not be able to sell produced oil and natural gas at an economical price point, especially during the second quarter of 2020. As a result, operators may be forced to curtail production, shut-in producing wells or seek other cost-cutting measures until commodity prices increase.

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 will 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 and potential scaled-back production and shut-in of producing wells. 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 months ended March 31, 2020 and 2019.

	Three Months Ended March 31,				Percent Change
	2020		2019
Average market closing prices (1)
Oil (per Bbl)	$	45.77	$	54.74		-16.4	%
Natural gas (per Mcf)	$	1.90	$	2.92		-34.9	%

(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 months ended March 31, 2020 and 2019.

	Three Months Ended March 31,
	2020		Percent of Revenue			2019		Percent of Revenue			Percent Change
Total revenues	$	11,103,534		100.0	%	$	10,091,345		100.0	%		10.0	%
Production expenses		2,052,237		18.5	%		2,818,717		27.9	%		-27.2	%
Production taxes		992,341		8.9	%		810,793		8.0	%		22.4	%
Depreciation, depletion, amortization and accretion		4,564,861		41.1	%		3,433,551		34.0	%		32.9	%
General and administrative expenses		565,297		5.1	%		494,482		4.9	%		14.3	%
Production (BOE):
Oil		264,055					172,705					52.9	%
Natural gas		28,664					45,788					-37.4	%
Natural gas liquids		30,173					43,716					-31.0	%
Total		322,892					262,209					23.1	%
Average sales price per unit:
Oil (per Bbl)	$	38.74				$	46.85					-17.3	%
Natural gas (per Mcf)		2.06					3.50					-41.1	%
Natural gas liquids (per Bbl)		17.21					23.75					-27.5	%
Combined (per BOE)		34.39					38.49					-10.7	%
Average unit cost per BOE:
Production expenses		6.36					10.75					-40.8	%
Production taxes		3.07					3.09					-0.6	%
Depreciation, depletion, amortization and accretion		14.14					13.09					8.0	%
Capital expenditures	$	15,415,306				$	158,117

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Oil, Natural Gas and NGL Revenues

For the three months ended March 31, 2020, revenues for oil, natural gas and NGL sales were $11.1 million. Revenues for the sale of crude oil were $10.2 million, which resulted in a realized price of $38.74 per barrel. Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $2.06 per Mcf. Revenues for the sale of NGLs were $0.5 million, which resulted in a realized price of $17.21 per BOE of sold production. For the three months ended March 31, 2019, revenues for oil, natural gas and NGL sales were $10.1 million. Revenues for the sale of crude oil were $8.1 million, which resulted in a realized price of $46.85 per barrel. Revenues for the sale of natural gas were $1.0 million, which resulted in a realized price of $3.50 per Mcf. Revenues for the sale of NGLs were $1.0 million, which resulted in a realized price of $23.75 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. The Partnership expects its oil price differential to increase during the second quarter of 2020, as the oil supply produced in the Sanish field exceeds demand and the storage capacity available at refineries.

The Partnership’s results for the three months ended March 31, 2020 were positively impacted by the completion of 14 new wells during the fourth quarter of 2019 and the first quarter of 2020, which contributed to increases in the Partnership’s sold production volumes of oil when compared to the same period of 2019. Sold production for the Sanish Field Assets was approximately 3,500 BOE and 2,900 BOE per day for the three months ended March 31, 2020 and 2019. Sold production increases realized for oil during the first quarter of 2020 were partially offset by the Partnership’s realized sales prices for oil, which were negatively impacted by decreases in market commodity prices for oil, in comparison to 2019.

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. Also, the production volumes of gas and NGLs decreased during the first quarter of 2020 when compared to the same period of 2019 primarily due to a reduction in the number of wells producing gas and NGLs during the development of new wells and natural production declines. The sale of gas and NGL production from the Partnership’s newly completed wells partially offset these noted decreases to production.

Due to the inability to produce, process and sell oil and natural gas at economical prices, many operators in the Sanish field, including Whiting, have announced plans to curtail daily production, shut-in producing wells or seek other cost-cutting measures, starting in April 2020. The Partnership anticipates these curtailments and shut-ins will continue as long as producing is uneconomical. Consequently, the Partnership expects declines in its oil, natural gas and NGL production through at least the second quarter of 2020. In addition, if the 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 26 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 26 in-process wells are completed.

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 March 31, 2020 and 2019, production expenses were $2.1 million and $2.8 million, respectively, and production expenses per BOE of sold production were $6.36 and $10.75, respectively. Production expenses per BOE for the first quarter of 2020 were below the prior year expense per BOE due to (i) certain of the Partnership’s existing producing wells being temporarily suspended for the development of new wells, as noted above, and (ii) the decline in production of natural gas and NGLs. The production costs specific to the processing, treating and marketing of natural gas and NGL are higher than those associated with oil, so a reduction in sold natural gas and NGL results in a greater decrease in these production expenses than the corresponding increase in production expenses for new oil production.

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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 March 31, 2020 and 2019 were $1.0 million (9% of revenue) and $0.8 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 March 31, 2020 and 2019 was $4.6 million and $3.4 million, and DD&A per BOE of sold production was $14.14 and $13.09, 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 the Partnership’s investment in new wells during the fourth quarter of 2019 and first quarter of 2020, and the cost to complete the new wells. 

General and Administrative Costs

General and administrative costs for the three months ended March 31, 2020 and 2019 was $0.6 million and $0.5 million, respectively. The principal components of general and administrative expense are accounting, legal and consulting fees.

Gain on Derivatives

Periodically, the Partnership has entered into derivative contracts (costless collars) with the objective to manage the commodity price risk on a portion of anticipated future oil production. The Partnership settled three monthly derivative contracts during the first quarter of 2020. 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 Partnership had no outstanding contracts at March 31, 2020. The following table presents the Partnership’s gain at settlement of its matured derivative instruments and the non-cash gain the Partnership recorded during the three months ended March 31, 2020.

	Three Months Ended March 31, 2020
Settlements on matured derivatives (1)	$	257,040
Gain on mark-to-market of derivatives		183,850
Gain on derivatives	$	440,890

(1) Settlements on matured derivatives reflect gains on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The Partnership’s production contracts that expired during the period represented 82,000 barrels of produced oil, resulting in a gain of $3.13 per barrel of oil.

Interest Expense

Interest expense, net, for the three months ended March 31, 2020 and 2019 was $0.4 million and $0.2 million, respectively. The primary component of Interest expense, net, during the three-month periods ended March 31, 2020 and 2019 was interest expense on the Credit Facility. The increase for the three months ended March 31, 2020, as compared to the same period of 2019, is due to increased borrowings under the Credit Facility.

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Supplemental Non-GAAP Measure

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

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

The following table reconciles the Partnership’s GAAP net income to Adjusted EBITDAX for the three months ended March 31, 2020 and 2019.

	Three Months Ended March 31, 2020			Three Months Ended March 31, 2019
Net income	$	2,933,427		$	2,339,974
Interest expense, net		436,261			193,828
Depreciation, depletion, amortization and accretion		4,564,861			3,433,551
Exploration expenses		-			-
Non-cash gain on mark-to-market of derivatives		(183,850	)		-
Adjusted EBITDAX	$	7,750,699		$	5,967,353

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 March 31, 2020, the Partnership has borrowed $40 million under its revolving credit facility, which represents all availability under the revolving credit facility. At March 31, 2020, the Partnership held cash and cash equivalents of $2.7 million and for the three months ended March 31, 2020, the Partnership generated $4.2 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 meet its current obligations. 

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 7. Capital Contribution and Partners’ Equity” in Part I, Item 1 of this Form 10-Q.

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Distributions

For the three months ended March 31, 2020 and 2019, the Partnership paid distributions of $0.241644 and $0.349041 per common unit, or $4.6 million and $6.6 million, respectively. The Partnership generated $4.2 million and $5.7 million, respectively, in cash flow from operating activities for the three months ended March 31, 2020 and 2019.

In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to recent market volatility, as discussed in “Drilling Program, Oil Demand, Liquidity and Going Concern Considerations” above. The Partnership will accumulate unpaid distributions based on an annualized return of seven percent, and all accumulated unpaid distributions are required to be paid before final Payout occurs, as defined in the Partnership’s prospectus. As of March 31, 2020, the unpaid Payout Accrual totaled $0.107397 per common unit, or approximately $2.0 million. The General Partner will continue to monitor the Partnership’s distribution policy on a monthly basis in conjunction with the Partnership’s projected cash requirements for operations, capital expenditures for new wells, debt service and any restrictions under its Credit Facility. As discussed in “Note 4. Debt” of Part I, Item 1 of this Form 10-Q and pursuant to the anticipated waiver to be granted by its lender, the Partnership will not be permitted to pay distributions of any amount without lender approval.

Oil and Natural Gas Properties

The Partnership incurred approximately $15.4 million and $0.2 million in capital expenditures for the three months ended March 31, 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 $65 million. Through March 31, 2020, the Partnership has incurred approximately $39 million in capital expenditures related to the 43 wells. As of March 31, 2020, 14 of these wells have been completed, 26 were in process and drilling had not yet commenced on 3 wells. Of the 26 in-process wells, the Partnership anticipates that up to seven wells may be completed during the second quarter of 2020; however, the Partnership does not believe any wells completed during the second quarter of 2020 will be brought into production while commodity pricing is low. Further, the Partnership anticipates that the remaining 19 in-process wells will be drilled, but uncompleted (“DUC”) by Whiting; the timing for completion of DUC wells is dependent upon an increase in commodity pricing along with the availability of either cash flow from operations or other capital resources. The Partnership estimates it will incur approximately $5 to $7 million in additional capital expenditures during the second quarter of 2020 based upon the status of these wells when Whiting suspended its drilling program. However, the factors described in “Current Price Environment” along with Whiting’s bankruptcy proceedings that commenced in April 2020 (see “Subsequent Events” below), it is difficult to predict the amount and timing of capital expenditures for the remainder of 2020, and estimated capital expenditures could be significantly different from amounts actually invested.

Based upon current information from its operators, the Partnership still anticipates all well locations recorded as proved undeveloped reserves (“PUD”) at December 31, 2019 will be drilled and converted to proved developed reserves within five years from initially being recorded. Therefore, in addition to the approximate $26 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 $60 to $75 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 there are any changes to operator capital investment plans or delays in the development of PUD reserves, the Partnership may be required to reclassify PUD locations and the associated reserves which are no longer projected to be drilled within five years. 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.

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See further discussion in “Note 8. Related Parties” in Part I, Item 1 of this Form 10-Q.

Subsequent Events

On April 1, 2020, 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. Whiting has indicated its business will operate in the normal course without material disruption to its vendors, partners or employees, including the Partnership. At this time, the Partnership is unable to estimate the impact this will have on its operating results, if any.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership has a variable interest rate on its Credit Facility that is subject to market changes in interest rates. Information regarding the Partnership’s Credit Facility 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 March 31, 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 March 31, 2020 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal controls over financial reporting.

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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 covenant violations under its Credit Facility.

As of March 31, 2020, the Partnership was in violation of the Current Ratio covenant under its Credit Facility. The Partnership anticipates it will enter into a waiver agreement with the lender group under the Credit Facility, which the Partnership anticipates will waive the Current Ratio covenant until September 30, 2020. Even if the anticipated waiver is received, if the Partnership violates this or other 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 March 31, 2020) to the lenders.

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 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 second quarter of 2020 and likely 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.

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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 continue to decline or remain at current levels 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. If crude oil prices continue to decline or remain at current levels 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 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, the 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 restructure its loan agreement or 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.

As of March 31, 2020, the Partnership was not in compliance with its current ratio covenant under its Amended Loan Agreement. The Partnership anticipates it will enter into a waiver agreement with its lender group to waive compliance with the current ratio covenant within the Amended Loan Agreement until September 30, 2020. Refer to Item 1 – Financial Statements (Unaudited) and Notes to Consolidated Financial Statements: Note 4. Debt.

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Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit No.	Description
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 March 31, 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 March 31, 2020, formatted in iXBRL and contained in Exhibit 101

*Filed herewith.

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SIGNATURES

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

Energy 11, L.P.
By: Energy 11 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: June 22, 2020

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