Energy 11 10Q 2021 Q2 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 June 30, 2021

☐	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 August 12, 2021, the Partnership had 18,973,474 common units outstanding.

Energy 11, L.P.

Form 10-Q

Index

			Page Number
PART I. FINANCIAL INFORMATION

	Item 1.	Financial Statements (Unaudited)

		Consolidated Balance Sheets – June 30, 2021 and December 31, 2020	3

		Consolidated Statements of Operations – Three and six months ended June 30, 2021 and 2020	4

		Consolidated Statements of Partners’ Equity – Three and six months ended June 30, 2021 and 2020	5

		Consolidated Statements of Cash Flows – Six months ended June 30, 2021 and 2020	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	24

	Item 3.	Defaults upon Senior Securities	24

	Item 4.	Mine Safety Disclosures	24

	Item 5.	Other Information	24

	Item 6.	Exhibits	24

Signatures			25

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Energy 11, L.P.

Consolidated Balance Sheets

	June 30,			December 31,
	2021			2020
	(unaudited)
Assets
Cash and cash equivalents	$	5,647,433		$	1,608,301
Restricted cash and cash equivalents		0			855,518
Accounts receivable		8,514,241			5,890,971
Other current assets, net		227,312			257,524
Total Current Assets		14,388,986			8,612,314

Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $85,563,252 and $75,765,289, respectively		326,804,903			323,200,183
Other assets		236,539			0
Total Assets	$	341,430,428		$	331,812,497

Liabilities
Revolving credit facility	$	0		$	40,000,000
Affiliate term loan		0			6,000,000
Accounts payable and accrued expenses		11,745,969			3,299,810
Derivative liability		0			602,760
Total Current Liabilities		11,745,969			49,902,570

Revolving credit facility		40,063,389			0
Asset retirement obligations		1,684,869			1,564,105
Total Liabilities		53,494,227			51,466,675

Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)		287,937,928			280,347,549
General partner's interest		(1,727	)		(1,727	)
Class B Units (62,500 units issued and outstanding, respectively)		0			0
Total Partners’ Equity		287,936,201			280,345,822

Total Liabilities and Partners’ Equity	$	341,430,428		$	331,812,497

See notes to consolidated financial statements.

Index

Energy 11, L.P.

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended			Three Months Ended			Six Months Ended			Six Months Ended
	June 30, 2021			June 30, 2020			June 30, 2021			June 30, 2020

Revenues
Oil	$	11,868,210		$	3,995,270		$	22,470,147		$	14,225,003
Natural gas		865,226			401,106			2,343,986			755,680
Natural gas liquids		1,146,037			356,142			2,669,416			875,369
Total revenue		13,879,473			4,752,518			27,483,549			15,856,052

Operating costs and expenses
Production expenses		2,867,144			2,120,130			5,523,221			4,172,367
Production taxes		1,093,447			416,550			2,095,399			1,408,891
General and administrative expenses		315,832			355,137			847,130			920,434
Depreciation, depletion, amortization and accretion		4,952,799			5,897,854			9,840,216			10,462,715
Total operating costs and expenses		9,229,222			8,789,671			18,305,966			16,964,407

Operating income (loss)		4,650,251			(4,037,153	)		9,177,583			(1,108,355	)

Gain (loss) on derivatives, net		0			0			(579,660	)		440,890
Interest expense, net		(523,341	)		(404,368	)		(1,007,544	)		(840,629	)
Total other expense, net		(523,341	)		(404,368	)		(1,587,204	)		(399,739	)

Net income (loss)	$	4,126,910		$	(4,441,521	)	$	7,590,379		$	(1,508,094	)

Basic and diluted net income (loss) per common unit	$	0.22		$	(0.23	)	$	0.40		$	(0.08	)

Weighted average common units outstanding - basic and diluted		18,973,474			18,973,474			18,973,474			18,973,474

See notes to consolidated financial statements.

Index

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, 2019		18,973,474	$	287,737,698			62,500	$	-	$	(1,727	)	$	287,735,971
Distributions declared and paid to common units ($0.241644 per common unit)		-		(4,584,826	)		-		-		-			(4,584,826	)
Net income - three months ended March 31, 2020		-		2,933,427			-		-		-			2,933,427
Balances - March 31, 2020		18,973,474		286,086,299			62,500		-		(1,727	)		286,084,572
Net loss - three months ended June 30, 2020		-		(4,441,521	)		-		-		-			(4,441,521	)
Balances - June 30, 2020		18,973,474	$	281,644,778			62,500	$	-	$	(1,727	)	$	281,643,051

Balances - December 31, 2020		18,973,474	$	280,347,549			62,500	$	-	$	(1,727	)	$	280,345,822
Net income - three months ended March 31, 2021		-		3,463,469			-		-		-			3,463,469
Balances - March 31, 2021		18,973,474		283,811,018			62,500		-		(1,727	)		283,809,291
Net income - three months ended June 30, 2021		-		4,126,910			-		-		-			4,126,910
Balances - June 30, 2021		18,973,474	$	287,937,928			62,500	$	-	$	(1,727	)	$	287,936,201

See notes to consolidated financial statements.

Index

Energy 11, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended			Six Months Ended
	June 30, 2021			June 30, 2020

Cash flow from operating activities:
Net income (loss)	$	7,590,379		$	(1,508,094	)

Adjustments to reconcile net income (loss) to cash from operating activities:
Depreciation, depletion, amortization and accretion		9,840,216			10,462,715
Gain on mark-to-market of derivatives		(602,760	)		(183,850	)
Non-cash expenses, net		99,650			20,327

Changes in operating assets and liabilities:
Accounts receivable		(2,623,270	)		3,028,205
Other current assets		96,140			95,982
Accounts payable and accrued expenses		158,668			1,070,422

Net cash flow provided by operating activities		14,559,023			12,985,707

Cash flow from investing activities:
Additions to oil and natural gas properties		(5,043,870	)		(17,083,210	)

Net cash flow used in investing activities		(5,043,870	)		(17,083,210	)

Cash flow from financing activities:
Cash paid for loan costs		(394,928	)		0
Proceeds from BancFirst revolving credit facility		40,063,389			0
Proceeds from (payments on) Simmons revolving credit facility		(40,000,000	)		16,000,000
Payments on affiliate term loan		(6,000,000	)		0
Distributions paid to limited partners		0			(4,584,826	)

Net cash flow provided by (used in) financing activities		(6,331,539	)		11,415,174

Increase in cash, cash equivalents and restricted cash		3,183,614			7,317,671
Cash, cash equivalents and restricted cash, beginning of period		2,463,819			348,550

Cash, cash equivalents and restricted cash, end of period	$	5,647,433		$	7,666,221

Interest paid	$	731,069		$	861,825

Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$	9,812,130		$	19,487,513

See notes to consolidated financial statements.

Index

Energy 11, L.P.

Notes to Consolidated Financial Statements

June 30, 2021

(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 June 30, 2021, the Partnership owned an approximate 25% non-operated working interest in 256 producing wells, an estimated approximate 17% non-operated working interest in 12 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) operates substantially all of the Sanish Field Assets.

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

The Partnership’s fiscal year ends on December 31.

Note 2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying 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 2020 Annual Report on Form 10-K. Operating results for the three and six months ended June 30, 2021 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2021.

Use of Estimates

The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Revenue Recognition

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

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

Index

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.

Net Income (Loss) Per Common Unit

Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (loss) per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and six months ended June 30, 2021 and 2020. 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 (loss) per common unit until such time that it is probable Payout (as discussed in Note 7) will occur.

Note 3. Oil and Natural Gas Investments

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

During 2018, 6 wells were completed by the Partnership’s operators. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million.

Since the beginning of 2019, the Partnership has elected to participate in the drilling and completion of 48 new wells in the Sanish field. NaN (35) of these 48 wells have been completed and were producing at June 30, 2021; the Partnership has an approximate non-operated working interest of 21% in these 35 wells. The Partnership has an estimated approximate non-operated working interest of 17% in the 12 wells that are in-process as of June 30, 2021. The Partnership has an estimated approximate non-operated working interest of 14% in 1 well that had not commenced drilling as of June 30, 2021. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 48 wells is approximately $64 million, of which approximately $53 million was incurred as of June 30, 2021.

In addition to the approximate $10 to $12 million to complete the 48 wells discussed above, the Partnership estimates it may incur an additional $8 to $12 million in capital expenditures during the second half of 2021 based on the best available information regarding current capital investment plans from its operators. However, many factors outside the Partnership’s control make it difficult to predict the amount and timing of capital expenditures for the remainder of 2021, and estimated capital expenditures could be significantly different from amounts actually invested.

Note 4. Debt

Revolving Credit Facilities

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

Index

On May 13, 2021, the Partnership and its wholly-owned subsidiary, as borrowers, entered into a loan agreement (“BF Loan Agreement”) with BancFirst, as administrative agent for the lenders (the “Lender”), which provides for a revolving credit facility (“BF Credit Facility”) with an approved maximum credit amount (“Maximum Credit Amount”) of $60 million, subject to borrowing base restrictions. The Partnership paid an origination fee of 0.50% of the Maximum Credit Amount, or $300,000, and is subject to an additional fee of 0.25% on any incremental increase to the borrowing base. Total capitalized loan costs were approximately $0.4 million and are being amortized over the life of the BF Credit Facility. Approximately $0.2 million of the deferred loan costs are recorded as Other current assets, net and the other approximate $0.2 million in deferred loan costs are recorded as Other assets on the Partnership’s consolidated balance sheet. The Partnership also is required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the Revolving Credit Facility, based on borrowings outstanding during a quarter. The maturity date is March 1, 2024.

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

Under the BF Loan Agreement, the initial borrowing base was $60 million. The Partnership’s borrowing base is reduced by a Monthly Commitment Reduction, which is initially stipulated to be $1 million. Therefore, as of June 30, 2021, the borrowing base was $59 million. The borrowing base and Monthly Commitment Reduction are subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period. Outstanding borrowings under the BF Credit Facility cannot exceed the lesser of the borrowing base or the Maximum Credit Amount at any time. The interest rate is equal to the Wall Street Journal Prime Rate plus 0.50%, with a floor of 4.00%.

Also under the BF Loan Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production. The Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is less than 50%, and at least 50% of its rolling 24-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 50%. See Note 6. Risk Management for more information on the Partnership’s risk management program as required under the BF Loan Agreement.

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

●

A minimum ratio of trailing 12-month EBITDAX to debt service coverage of 1.20 to 1.00

●

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

The BF Loan Agreement restricts the Partnership’s ability to pay limited partner distributions until the outstanding balance of the BF Credit Facility is equal to or less than 50% of the Maximum Credit Amount, at which point the Partnership is permitted to make distributions so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred.

The Partnership was in compliance with its applicable covenants at June 30, 2021.

At June 30, 2021, the outstanding balance on the BF Credit Facility was approximately $40 million, and the interest rate for the BF Credit Facility was 4.00%. As of June 30, 2021 and December 31, 2020, the outstanding balance on the BF Credit Facility and the Simmons Credit Facility was approximately $40 million, which approximated the fair market value of each credit facility. The Partnership estimated the fair value of its credit facilities 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.

Index

Term Loan from Affiliate

On July 21, 2020, the Partnership, as borrower, entered into a loan agreement with GKDML, LLC (“GKDML”), which provided for an unsecured, one-year term loan (“Term Loan” or “Affiliate Loan”) in the amount of $15 million. GKDML is owned and managed by Glade M. Knight and David S. McKenney, the Chief Executive Officer and the Chief Financial Officer, respectively, of the General Partner. The Term Loan was repaid in full during March 2021, and the Partnership did not incur a penalty for prepayment. The Term Loan bore interest at a variable rate based on LIBOR plus a margin of 2.00%, with a LIBOR floor of 0%. Interest was payable monthly.

To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A. on July 21, 2020 (“GKDML Loan”). The GKDML Loan was also repaid in March 2021, had substantially the same terms as the Term Loan and was personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney did not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership reimbursed GKDML for all costs of the GKDML Loan.

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:

	2021		2020
Balance at January 1	$	1,564,105	$	1,452,734
Well additions		78,511		27,844
Accretion		42,253		40,608
Revisions		0		0
Balance at June 30	$	1,684,869	$	1,521,186

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.

In accordance with the amended Simmons Loan Agreement discussed in Note 4. Debt, the Partnership was required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 2020 through February 2021. 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 did not settle any contracts during the second quarter of 2021 and had no outstanding contracts at June 30, 2021. The following table presents the settlement gain (loss) of matured derivative instruments and non-cash mark-to-market gains for the periods presented.

	Six Months Ended June 30, 2021			Six Months Ended June 30, 2020
Settlement gain (loss) on matured derivatives	$	(1,182,420	)	$	257,040
Gain on mark-to-market of derivatives		602,760			183,850
Gain (loss) on derivatives, net	$	(579,660	)	$	440,890

Index

Settlements on matured derivatives above reflect realized gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash) gains above represent the change in fair value of derivative instruments which were held at period-end. Unrealized gains or losses do not represent actual settlements or payments made to or from the counterparty.

In July 2021, the Partnership began its risk management program required under the BF Loan Agreement (see Note 4. Debt) by entering into costless collar derivative contracts for the period from July 2021 to July 2023, as shown in the table below. The Partnership did not pay or receive a premium related to the costless collars, and the contracts will be settled monthly.

Settlement Period	Basis	Product	Volume	Floor / Ceiling Prices ($)
07/2021 - 12/2021	NYMEX	Oil (bbls)	192,000	50.00 / 83.50
01/2022 - 06/2022	NYMEX	Oil (bbls)	173,000	50.00 / 80.00
07/2022 - 06/2023	NYMEX	Oil (bbls)	307,000	50.00 / 72.00

08/2021 - 07/2022	Henry Hub	Gas (MMbtu)	440,000	2.00 / 7.00
08/2022 - 07/2023	Henry Hub	Gas (MMbtu)	360,000	2.00 / 4.50

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;

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●

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

In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to market volatility caused by the COVID-19 pandemic 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 June 30, 2021, the unpaid Payout Accrual totaled $1.875616 per common unit, or approximately $36 million. As discussed in Note 4. Debt, the Partnership must meet certain conditions under the BF Loan Agreement before distributions to limited partners may resume.

For the six months ended June 30, 2020, the Partnership paid distributions of $0.241644, or $4.6 million.

Note 8. Related Parties

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

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

For the three and six months ended June 30, 2021, approximately $30,000 and $62,000 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 June 30, 2021, approximately $30,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets. For the three and six months ended June 30, 2020, approximately $98,000 and $190,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership.

On January 31, 2018, the Partnership entered into a cost sharing agreement with ER12 that gave ER12 access to the Partnership’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The cost sharing agreement reduced these accounting and asset management costs to the Partnership, as these shared day-to-day costs were split evenly between the two partnerships. The shared costs were based on actual costs incurred with no mark-up or profit to the Partnership. Any other direct third-party costs were paid by the party receiving the services. For the three and six months ended June 30, 2020, approximately $64,000 and $140,000, respectively, of expenses subject to the cost sharing agreement were incurred by ER12 and have been reimbursed to the Partnership. In October 2020, the cost sharing agreement was terminated by ER12, effective December 31, 2020.

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

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Costs and expenses attributable to the services performed by the Administrator under the ASA will be reimbursed by the Partnership. All Administrator costs and expenses will be accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses to be reimbursed under the ASA may include, but are not limited to, employee wages and benefits, rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. For the three and six months ended June 30, 2021, approximately $151,000 and $291,000, respectively, of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator.

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

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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, 2020 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;
●	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, 2020.

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.

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As of June 30, 2021, the Partnership owned an approximate 25% non-operated working interest in 256 producing wells, an estimated approximate 17% non-operated working interest in 12 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), one of the largest producers in the basin, operates substantially all of the Sanish Field Assets.

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

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

During 2018, six wells were completed by the Partnership’s operators. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million.

Since the beginning of 2019, the Partnership has elected to participate in the drilling and completion of 48 new wells in the Sanish field. Thirty-five (35) of these 48 wells have been completed and were producing at June 30, 2021; the Partnership has an approximate non-operated working interest of 21% in these 35 wells. The Partnership has an estimated approximate non-operated working interest of 17% in the 12 wells that are in-process as of June 30, 2021. The Partnership has an estimated approximate non-operated working interest of 14% in one well that had not commenced drilling as of June 30, 2021. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 48 wells is approximately $64 million, of which approximately $53 million was incurred as of June 30, 2021. See additional detail in “Oil and Natural Gas Properties” below.

Current Price Environment

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

The outbreak of a novel coronavirus (“COVID-19”) in China in December 2019 significantly impacted the global economy throughout 2020, and the domestic oil and gas industry was especially impacted as demand for oil, natural gas and other hydrocarbons substantially declined, beginning in March and April 2020. In addition to the outbreak of COVID-19, Saudi Arabia and Russia, two of the largest worldwide producers of crude oil, engaged in a price war during March and April 2020 that ultimately led to excess crude oil and natural gas inventory and congested supply chain channels, which weighed negatively on commodity prices while demand was low. Demand for oil and natural gas began to return in the fourth quarter of 2020 as government-mandated COVID-19 restrictions have eased. The increased demand and production restraint by domestic and foreign operators have contributed to higher commodity prices, with oil prices averaging over $70 per barrel in June 2021.

The Partnership’s revenues and cash flow from operations are highly sensitive to changes in oil and natural gas prices and to levels of production. If commodity prices significantly drop, such as the decline in the second quarter of 2020, and remain low, the Partnership will see a reduction in available capital for the development of its undrilled wellsites. Future growth is dependent on the Partnership’s ability to add reserves in excess of production. In addition to commodity price fluctuations, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.

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The following table lists average NYMEX prices for oil and natural gas for the three and six months ended June 30, 2021 and 2020.

	Three Months Ended June 30,				Percent			Six Months Ended June 30,				Percent
	2021		2020		Change			2021		2020		Change
Average market closing prices ⁽¹⁾
Oil (per Bbl)	$	66.17	$	28.00		136.3	%	$	62.22	$	36.82		69.0	%
Natural gas (per Mcf)	$	2.95	$	1.70		73.5	%	$	3.22	$	1.80		78.9	%

(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 table summarizes the results from operations, including production, of the Partnership’s non-operated working interest for the three and six months ended June 30, 2021 and 2020. The effect of the outbreak of COVID-19 during the first and second quarters of 2020 had a significant negative impact to the Partnership’s results from operations; as a result, the periods presented in the table below may not be directly comparable.

	Three Months Ended June 30,													Six Months Ended June 30,
	2021		Percent of Revenue			2020		Percent of Revenue			Percent Change			2021		Percent of Revenue			2020		Percent of Revenue			Percent Change
Total revenues	$	13,879,473		100.0	%	$	4,752,518		100.0	%		192.0	%	$	27,483,549		100.0	%	$	15,856,052		100.0	%		73.3	%
Production expenses		2,867,144		20.7	%		2,120,130		44.6	%		35.2	%		5,523,221		20.1	%		4,172,367		26.3	%		32.4	%
Production taxes		1,093,447		7.9	%		416,550		8.8	%		162.5	%		2,095,399		7.6	%		1,408,891		8.9	%		48.7	%
Depreciation, depletion, amortization and accretion		4,952,799		35.7	%		5,897,854		124.1	%		-16.0	%		9,840,216		35.8	%		10,462,715		66.0	%		-5.9	%
General and administrative expenses		315,832		2.3	%		355,137		7.5	%		-11.1	%		847,130		3.1	%		920,434		5.8	%		-8.0	%

Production (BOE):
Oil		196,817					250,706					-21.5	%		401,495					514,762					-22.0	%
Natural gas		46,725					42,524					9.9	%		90,664					71,189					27.4	%
Natural gas liquids		38,792					38,052					1.9	%		75,807					68,224					11.1	%
Total		282,334					331,282					-14.8	%		567,966					654,175					-13.2	%

Average sales price per unit:
Oil (per Bbl)	$	60.30				$	15.94					278.3	%	$	55.97				$	27.63					102.6	%
Natural gas (per Mcf)		3.09					1.57					96.8	%		4.31					1.77					143.5	%
Natural gas liquids (per Bbl)		29.54					9.36					215.6	%		35.21					12.83					174.4	%
Combined (per BOE)		49.16					14.35					242.7	%		48.39					24.24					99.6	%

Average unit cost per BOE:
Production expenses		10.16					6.40					58.7	%		9.72					6.38					52.4	%
Production taxes		3.87					1.26					208.0	%		3.69					2.15					71.6	%
Depreciation, depletion, amortization and accretion		17.54					17.80					-1.5	%		17.33					15.99					8.4	%

Capital expenditures	$	10,999,208				$	2,732,085							$	13,324,172				$	18,147,391

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Oil, natural gas and NGL revenues

For the three months ended June 30, 2021, revenues for oil, natural gas and NGL sales were $13.9 million. Revenues for the sale of crude oil were $11.9 million, which resulted in a realized price of $60.30 per barrel. Revenues for the sale of natural gas were $0.9 million, which resulted in a realized price of $3.09 per Mcf. Revenues for the sale of NGLs were $1.1 million, which resulted in a realized price of $29.54 per BOE of sold production. For the three months ended June 30, 2020, revenues for oil, natural gas and NGL sales were $4.8 million. Revenues for the sale of crude oil were $4.0 million, which resulted in a realized price of $15.94 per barrel. Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $1.57 per Mcf. Revenues for the sale of NGLs were $0.4 million, which resulted in a realized price of $9.36 per BOE of sold production.

For the six months ended June 30, 2021, revenues for oil, natural gas and NGL sales were $27.5 million. Revenues for the sale of crude oil were $22.5 million, which resulted in a realized price of $55.97 per barrel. Revenues for the sale of natural gas were $2.3 million, which resulted in a realized price of $4.31 per Mcf. Revenues for the sale of NGLs were $2.7 million, which resulted in a realized price of $35.21 per BOE of sold production. For the six months ended June 30, 2020, revenues for oil, natural gas and NGL sales were $15.9 million. Revenues for the sale of crude oil were $14.2 million, which resulted in a realized price of $27.63 per barrel. Revenues for the sale of natural gas were $0.8 million, which resulted in a realized price of $1.77 per Mcf. Revenues for the sale of NGLs were $0.9 million, which resulted in a realized price of $12.83 per BOE of sold production.

The Partnership’s results for the three and six months ended June 30, 2021 were positively impacted by the Partnership’s realized sales prices for oil, natural gas and NGLs. The Partnership’s realized sales prices exceeding the average oil market prices as described in “Current Price Environment” above, in comparison to the same periods of 2020, were primarily due to significantly improved oil differentials (see below) in 2021. The Partnership also realized increases exceeding average market gas and NGL prices, particularly due to the severe winter weather storms that resulted in power outages in Texas and other southern states in February 2021.

Offsetting higher realized sales prices, the Partnership’s sold oil production for the three and six months ended June 30, 2021 was negatively impacted primarily due to natural well declines. Production volumes per day fluctuate due to the timing of well completions; new wells often have high levels of production immediately following completion, then decline to more consistent levels. The Partnership’s sold oil production for the three and six months ended June 30, 2020 exceeded sold volumes for the same periods of 2021 due to the positive impact of 14 new wells completed during the fourth quarter of 2019 and first quarter of 2020. The Partnership did complete 13 new wells late in the second quarter of 2021, so the Partnership anticipates sold production volumes will increase during the second half of 2021. The Partnership’s operators have efficiently extracted natural gas from the Sanish Field Assets, ultimately reducing the natural gas shrink and yielding higher gas and NGL volumes during the first half of 2021, in comparison to the same period of 2020. Sold production for the Sanish Field Assets was approximately 3,100 BOE per day for the three and six months ended June 30, 2021, while sold production was approximately 3,600 BOE per day for the three and six months ended June 30, 2020.

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

Differentials

The realized prices per barrel of oil above are based upon the NYMEX benchmark price less a cost to distribute the oil, or the differential. Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation methods out of the Sanish field. Oil price differentials to the NYMEX benchmark price vary by operator based upon operator-specific contracts. Due to improvement in commodity prices and market-specific conditions in the Bakken during the first half of 2021, oil price differentials were less during the three and six months ended June 30, 2021, in comparison to the same periods of 2020.

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

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Operating costs and expenses

Production expenses

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

For the three months ended June 30, 2021 and 2020, production expenses were $2.9 million and $2.1 million, respectively, and production expenses per BOE of sold production were $10.16 and $6.40, respectively. For the six months ended June 30, 2021 and 2020, production expenses were $5.5 million and $4.2 million, respectively, and production expenses per BOE of sold production were $9.72 and $6.38, respectively. Production expenses per BOE increased in the three and six months ended June 30, 2021, in comparison to the same periods of 2020, primarily due (i) a decrease in sold production oil volumes along with fixed lease operating expenses, (ii) higher production and marketing costs associated with higher sold production gas and NGL volumes, and (iii) an increase in workover expenses as certain of the Partnership’s existing producing wells that had been temporarily suspended for the development of new wells required additional rework prior to being returned to full production.

Production taxes

Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. Taxes on the sale of gas and NGL products are less than taxes levied on the sale of oil. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGLs to total sales. Production taxes for the three months ended June 30, 2021 and 2020 were $1.1 million (8% of revenue) and $0.4 million (9% of revenue), respectively. Production taxes for the six months ended June 30, 2021 and 2020 were $2.1 million (8% of revenue) and $1.4 million (9% of revenue), respectively.

General and administrative expenses

General and administrative expenses for the three months ended June 30, 2021 and 2020 were $0.3 million and $0.4 million, respectively. General and administrative expenses for the six months ended June 30, 2021 and 2020 were $0.8 million and $0.9 million, respectively. The principal components of general and administrative expense are accounting, legal and consulting fees.

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 June 30, 2021 and 2020 was $5.0 million and $5.9 million, and DD&A per BOE of sold production was $17.54 and $17.80, respectively. DD&A for the six months ended June 30, 2021 and 2020 was $9.8 million and $10.5 million, and DD&A per BOE of sold production was $17.33 and $15.99, respectively. The decrease in DD&A expense for the three and six months ended June 30, 2021, in comparison to the same periods of 2020, is primarily due to the increase in the Partnership’s estimated proved undeveloped reserves (“PUDs”) resulting from changes to the Partnership’s future drilling schedule made as of June 30, 2021. The increase in DD&A expense per BOE of production for the six months ended June 30, 2021, compared to the same period of 2020, is primarily due to the Partnership’s continued investment in new wells and a decrease in sold production volumes.

Gain (loss) on derivatives, net

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In accordance with the amended Simmons Loan Agreement discussed in “Financing” below, the Partnership was required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 2020 through February 2021. The following table presents settlements of its matured derivative instruments and the non-cash, mark-to-market gains recorded during the periods presented.

	Six Months Ended June 30, 2021			Six Months Ended June 30, 2020
Settlement gains (losses) on matured derivatives	$	(1,182,420	)	$	257,040
Gain on mark-to-market of derivatives		602,760			183,850
Gain (loss) on derivatives, net	$	(579,660	)	$	440,890

The Partnership’s oil production contracts that expired during the six months ended June 30, 2021 represented approximately 105,000 barrels of oil. The Partnership’s realized loss of approximately $1.2 million equated to an approximate loss of $11.26 per barrel of oil. The Partnership’s natural gas production contracts that expired during the six months ended June 30, 2021 represented 120,000 MMBtu of natural gas; however, these natural gas production contracts were settled at no cost or benefit to the Partnership, as the contract price on the date of settlement was within the established floor and ceiling prices. The Partnership’s oil production contracts that expired during the six months ended June 30, 2020 represented approximately 82,000 barrels of oil. The Partnership’s realized gain of approximately $0.3 million equated to an approximate gain of $3.13 per barrel of oil.

The mark-to-market gains recorded for the three and six months ended June 30, 2021 and 2020 represent the change in fair value of the Partnership’s derivative instruments held at period-end. Unrealized gains and losses do not represent actual settlements or payments made to or from the counterparty.

In July 2021, the Partnership began its risk management program required under the BF Loan Agreement (see “Financing” below) by entering into costless collar derivative contracts for the period from July 2021 to July 2023, as shown in the table below. The Partnership did not pay or receive a premium related to the costless collars, and the contracts will be settled monthly.

Settlement Period	Basis	Product	Volume	Floor / Ceiling Prices ($)
07/2021 - 12/2021	NYMEX	Oil (bbls)	192,000	50.00 / 83.50
01/2022 - 06/2022	NYMEX	Oil (bbls)	173,000	50.00 / 80.00
07/2022 - 06/2023	NYMEX	Oil (bbls)	307,000	50.00 / 72.00

08/2021 - 07/2022	Henry Hub	Gas (MMbtu)	440,000	2.00 / 7.00
08/2022 - 07/2023	Henry Hub	Gas (MMbtu)	360,000	2.00 / 4.50

Interest expense, net

Interest expense, net, for the three months ended June 30, 2021 and 2020 was $0.5 million and $0.4 million, respectively. Interest expense, net, for the six months ended June 30, 2021 and 2020 was $1.0 million and $0.8 million, respectively. The primary component of Interest expense, net, during the three- and six-month periods ended June 30, 2021 was interest expense on the Simmons Credit Facility, the Affiliate Loan and the BF Credit Facility discussed below in “Financing.” The primary component of Interest expense, net, during the three- and six-month periods ended June 30, 2021 was interest expense on the Simmons Credit Facility.

Supplemental Non-GAAP Measure

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

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

The following table reconciles the Partnership’s GAAP net income to Adjusted EBITDAX for the three and six months ended June 30, 2021 and 2020.

	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020			Six Months Ended June 30, 2021			Six Months Ended June 30, 2020
Net income (loss)	$	4,126,910	$	(4,441,521	)	$	7,590,379		$	(1,508,094	)
Interest expense, net		523,341		404,368			1,007,544			840,629
Depreciation, depletion, amortization and accretion		4,952,799		5,897,854			9,840,216			10,462,715
Exploration expenses		-		-			-			-
Non-cash gain on mark-to-market of derivatives		-		-			(602,760	)		(183,850	)
Adjusted EBITDAX	$	9,603,050	$	1,860,701		$	17,835,379		$	9,611,400

Liquidity and Capital Resources

Historically, the Partnership’s principal sources of liquidity have been cash on hand, the cash flow generated from the Sanish Field Assets, and availability under the Partnership’s revolving credit facility, if any. The Partnership successfully refinanced its existing credit facility in May 2021 (see “Financing” below); therefore, the Partnership anticipates its cash on-hand, cash flow from operations and availability under its refinanced credit facility will be adequate to meet its liquidity requirements for at least the next 12 months, including completing the outstanding capital expenditures discussed below. Although the Partnership anticipates its cash on-hand, cash flow from operations and credit facility availability to be adequate to fund its cash requirements, if market prices for oil and natural gas decline and/or production from Partnership wells is not replenished through the completion of new well investments, the Partnership’s cash flow from operations may decline, which could have a significant impact on the Partnership’s available cash on-hand.

Financing

Revolving Credit Facilities

On May 13, 2021, the Partnership and its wholly-owned subsidiary, as borrowers, entered into a loan agreement (“BF Loan Agreement”) with BancFirst, as administrative agent for the lenders (the “Lender”), which provides for a revolving credit facility (“BF Credit Facility”) with an approved maximum credit amount (“Maximum Credit Amount”) of $60 million, subject to borrowing base restrictions. The Partnership paid an origination fee of 0.50% of the Maximum Credit Amount, or $300,000, and is subject to an additional fee of 0.25% on any incremental increase to the borrowing base. The Partnership also is required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the Revolving Credit Facility, based on borrowings outstanding during a quarter. The maturity date is March 1, 2024.

At closing, the Partnership borrowed approximately $40 million. The proceeds were used to pay the $40 million outstanding balance and accrued interest on the Simmons Credit Facility described above. Any further advances under the BF Credit Facility are to be used to fund capital expenditures for the development of the Partnership’s undrilled acreage. At June 30, 2021, the outstanding balance on the BF Credit Facility was approximately $40 million. Under the terms of the BF Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The BF Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells.

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Also under the BF Loan Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production. The Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is less than 50%, and at least 50% of its rolling 24-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 50%. See “Gain (loss) on derivatives, net” in Results from Operations above for more information on the Partnership’s risk management program as required under the BF Loan Agreement.

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

●

A minimum ratio of trailing 12-month EBITDAX to debt service coverage of 1.20 to 1.00

●

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

The Partnership was in compliance with its applicable covenants at June 30, 2021.

Term Loan from Affiliate

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

In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to market volatility caused by the COVID-19 pandemic and the impact on the Partnership’s operating cash flows. The Partnership will accumulate unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs. As of June 30, 2021, the unpaid Payout Accrual totaled $1.875616 per common unit, or approximately $36 million. As discussed in “Financing” above, the Partnership must meet certain conditions under the BF Loan Agreement before distributions to limited partners may resume.

For the six months ended June 30, 2020, the Partnership paid distributions of $0.241644, or $4.6 million.

Oil and Natural Gas Properties

The Partnership incurred approximately $13.3 million and $18.1 million in capital expenditures for the six months ended June 30, 2021 and 2020, respectively.

The Partnership anticipates its operators to complete the remaining 13 wells during the next six to nine months; however, completion of the wells is not in the Partnership’s control. In addition to the approximate $10 to $12 million to fully fund the completion of the 48 wells discussed above, the Partnership estimates it may incur an additional $8 to $12 million in capital expenditures during the second half of 2021 based on the best available information regarding current capital investment plans from its operators. Many factors outside the Partnership’s control make it difficult to predict the amount and timing of capital expenditures for the remainder of 2021, and estimated capital expenditures could be significantly different from amounts actually invested. The Partnership anticipates that it may be obligated to invest $25 to $30 million in capital expenditures from 2022 through 2026 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.

The Partnership’s liquidity is currently dependent upon cash on-hand, cash from operations and availability under the BF Credit Facility discussed above. If the Partnership is not able to generate sufficient cash from operation or there is no availability under the BF Credit Facility to fund capital expenditures, it may not be able to complete its capital obligations presented by its operators or participate fully in future wells. If an operator elects to complete drilling or other significant capital expenditure activity and the Partnership is unable to fund the capital expenditures, the General Partner may decide to farmout the well. Also, if a well is proposed under the operating agreement for one of the properties the Partnership owns, the General Partner may elect to “non-consent” the well. Non-consenting a well will generally cause the Partnership not to be obligated to pay the costs of the well, but the Partnership will not be entitled to the proceeds of production from the well until a penalty is received by the parties that drilled the well.

Transactions with Related Parties

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

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership had variable interest rates on its Simmons Credit Facility and Affiliate Loan that were subject to market changes in interest rates. In addition, the Partnership’s BF Credit Facility is subject to a variable interest rate. Information regarding the Partnership’s Simmons Credit Facility, the Affiliate Loan and the BancFirst 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 June 30, 2021 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 June 30, 2021 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

For a discussion of the Partnership’s potential risks and uncertainties, see the section titled “Risk Factors” in the Partnership’s 2020 Annual Report on Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2020 Form 10-K.

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

Not applicable.

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit No.		Description
10.1		Credit Agreement dated as of May 13, 2021 among Energy 11 Operating Company, LLC and Energy 11, L.P., as Borrowers, BancFirst, as Administrative Agent and the Lenders Party hereto (incorporated by reference from Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q dated May 17, 2021)
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 June 30, 2021 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Partners’ Equity, (iv) the Consolidated Statements of Cash Flows, and (v) related notes to these consolidated financial statements, tagged as blocks of text and in detail*
104		The cover page from the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, 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: August 12, 2021

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Energy 11 10-Q2021 Q2 Quarterly report

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