energy1120190331

10-Q 1 energy1120190331_10q.htm FORM 10-Q energy1120190331_10q.htm

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, 2019

☐	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

Common Units, limited partner interest

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 April 30, 2019, the Partnership had 18,973,474 common units outstanding.

Index

Energy 11, L.P.

Form 10-Q

Index

			Page Number
PART I. FINANCIAL INFORMATION

	Item 1.	Financial Statements (Unaudited)

		Consolidated Balance Sheets – March 31, 2019 and December 31, 2018	3

		Consolidated Statements of Operations – Three months ended March 31, 2019 and 2018	4

		Consolidated Statements of Partners’ Equity – Three months ended March 31, 2019 and 2018	5

		Consolidated Statements of Cash Flows – Three months ended March 31, 2019 and 2018	6

		Notes to Consolidated Financial Statements	7

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	18

	Item 4.	Controls and Procedures	18

PART II. OTHER INFORMATION

	Item 1.	Legal Proceedings	19

	Item 1A.	Risk Factors	19

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	19

	Item 3.	Defaults upon Senior Securities	19

	Item 4.	Mine Safety Disclosures	19

	Item 5.	Other Information	19

	Item 6.	Exhibits	19

Signatures			20

Index

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Energy 11, L.P.

Consolidated Balance Sheets

(Unaudited)

	March 31,			December 31,
	2019			2018

Assets
Cash and cash equivalents	$	2,542,202		$	3,685,327
Oil, natural gas and natural gas liquids revenue receivable		5,669,600			6,269,243
Other current assets		133,347			198,770
Total Current Assets		8,345,149			10,153,340

Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $44,221,966 and $40,806,378, respectively		309,859,515			313,116,985
Total Assets	$	318,204,664		$	323,270,325

Liabilities
Revolving credit facility	$	13,800,000		$	13,800,000
Accounts payable and accrued expenses		1,629,577			2,430,656
Total Current Liabilities		15,429,577			16,230,656

Asset retirement obligations		1,312,031			1,294,067
Total Liabilities		16,741,608			17,524,723

Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)		301,464,783			305,747,329
General partner's interest		(1,727	)		(1,727	)
Class B Units (62,500 units issued and outstanding, respectively)		-			-
Total Partners’ Equity		301,463,056			305,745,602

Total Liabilities and Partners’ Equity	$	318,204,664		$	323,270,325

See notes to consolidated financial statements.

Index

Energy 11, L.P.

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended			Three Months Ended
	March 31, 2019			March 31, 2018

Revenues
Oil	$	8,092,070		$	10,644,693
Natural gas		961,112			932,998
Natural gas liquids		1,038,163			1,490,043
Total revenue		10,091,345			13,067,734

Operating costs and expenses
Production expenses		2,818,717			2,934,666
Production taxes		810,793			1,075,125
General and administrative expenses		494,482			381,616
Depreciation, depletion, amortization and accretion		3,433,551			3,967,770
Total operating costs and expenses		7,557,543			8,359,177

Operating income		2,533,802			4,708,557

Loss on derivatives		-			(1,162,255	)
Interest expense, net		(193,828	)		(220,857	)
Total other expense, net		(193,828	)		(1,383,112	)

Net income	$	2,339,974		$	3,325,445

Basic and diluted net income per common unit	$	0.12		$	0.18

Weighted average common units outstanding - basic and diluted		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, 2017		18,973,474	$	314,254,337			62,500	$	-	$	(1,727	)	$	314,252,610
Distributions declared and paid to common units ($0.299178 per common unit)		-		(5,676,446	)		-		-		-			(5,676,446	)
Net income - three months ended March 31, 2018		-		3,325,445			-		-		-			3,325,445
Balances - March 31, 2018		18,973,474	$	311,903,336			62,500	$	-	$	(1,727	)	$	311,901,609

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

See notes to consolidated financial statements.

Index

Energy 11, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended			Three Months Ended
	March 31, 2019			March 31, 2018

Cash flow from operating activities:
Net income	$	2,339,974		$	3,325,445

Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion		3,433,551			3,967,770
Loss on mark-to-market of derivatives		-			688,677
Non-cash expenses, net		11,198			11,352

Changes in operating assets and liabilities:
Oil, natural gas and natural gas liquids revenue receivable		599,643			(816,262	)
Other current assets		54,224			(5,380	)
Accounts payable and accrued expenses		(723,746	)		(118,935	)

Net cash flow provided by operating activities		5,714,844			7,052,667

Cash flow from investing activities:
Additions to oil and natural gas properties		(235,449	)		(2,730,755	)

Net cash flow used in investing activities		(235,449	)		(2,730,755	)

Cash flow from financing activities:
Cash paid for loan costs		-			(1,845	)
Payments on revolving credit facility		-			(7,000,000	)
Distributions paid to limited partners		(6,622,520	)		(5,676,446	)

Net cash flow used in financing activities		(6,622,520	)		(12,678,291	)

Decrease in cash and cash equivalents		(1,143,125	)		(8,356,379	)
Cash and cash equivalents, beginning of period		3,685,327			11,090,846

Cash and cash equivalents, end of period	$	2,542,202		$	2,734,467

Interest paid	$	190,642		$	231,792

See notes to consolidated financial statements.

Index

Energy 11, L.P.

Notes to Consolidated Financial Statements

March 31, 2019

(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, 2019, the Partnership owned an approximate 25-26% non-operated working interest in 221 currently producing wells and approximately 247 future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”), which is part of the Bakken shale formation in the Greater Williston Basin. Whiting Petroleum Corporation (“Whiting”) and Oasis Petroleum North America, LLC (“Oasis”), 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.

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 2018 Annual Report on Form 10-K. Operating results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2019.

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.

Reclassifications

Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current period presentation with no effect on previously reported net income, partners’ equity or cash flows.

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 no common units with a dilutive effect for the three months ended March 31, 2019 and 2018. 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 5) will occur.

Index

Recently Adopted Accounting Standards

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) No. 2016-02, Leases (Topic 842), which amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets as right-of-use assets and lease liabilities. The Partnership concluded there is no material impact to the Partnership’s consolidated financial statements and related disclosures. The Partnership adopted this standard as of January 1, 2019.

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, 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.

Note 4. Debt

On November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”) with Bank SNB (the “Lender”), which provides for a revolving credit facility (the “Credit Facility”) with an approved initial commitment amount of $20 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The commitment amount may be increased up to $75 million with Lender approval. The Partnership paid an origination fee of 0.30% of the Revolver Commitment Amount, or $60,000, and is subject to additional origination fees of 0.30% for any borrowings made in excess of the Revolver Commitment Amount. 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 maturity date is November 21, 2019. Although the Partnership does not have a commitment from a lender, it anticipates it will be able to refinance its existing credit facility on similar terms prior to maturity.

The interest rate, subject to certain exceptions, is 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 Loan Agreement. At March 31, 2019, the borrowing base was $30 million and the interest rate for the Credit Facility was approximately 5.34%.

The Credit Facility is available to provide additional liquidity for capital investments and other corporate working capital requirements. Under the terms of the Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The Credit Facility is secured by a mortgage and first lien position on at least 80% of the Partnership’s producing wells.

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

● a maximum leverage ratio

● a minimum current ratio

● maximum distributions

The Partnership was in compliance with the applicable covenants at March 31, 2019.

As of March 31, 2019 and December 31, 2018, the outstanding balance on the Credit Facility was $13.8 million, which approximates its fair market value. The Partnership estimated the fair value of its Credit Facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

Index

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. The Partnership also had outstanding derivative instruments as of March 31, 2018, which incurred a $1.2 million loss, comprised of losses on settled derivatives and a mark-to-market loss, during the three months ended March 31, 2018.

Note 5. 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%).

For the three months ended March 31, 2019 and 2018, the Partnership paid distributions of $0.349041 and $0.299178 per common unit, or $6.6 million and $5.7 million, respectively.

Index

Note 6. 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, 2019 and 2018, approximately $68,000 and $71,000 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, 2019, approximately $68,000 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, 2019 and 2018, 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, 2019 and 2018, approximately $65,000 and $47,000, 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, 2019, the approximately $65,000 due to the Partnership from ER12 is included in Other current assets in the consolidated balance sheets.

Note 7. Subsequent Events

In April 2019, the Partnership declared and paid $2.0 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

Index

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:

●	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, 2018 and the following:

●	that the Partnership’s strategy of acquiring oil and gas properties on attractive terms and developing those properties may not be successful or that the Partnership’s operations on properties acquired may not be successful;

●	general economic, market, or business conditions;

●	changes in laws or regulations;

●	the risk that the wells in which the Partnership acquires 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.

Index

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, 2018.

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, 2019, the Partnership owned an approximate 25-26% non-operated working interest in 221 currently producing wells and approximately 247 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.

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. The monthly average of $70.98 per barrel of oil in July 2018 represented the highest monthly average since November 2014. However, as a result of several of the factors discussed below, oil prices declined in November and December 2018, with December’s monthly average of $48.97 per barrel of oil being the lowest monthly average per barrel of oil since August 2017. In 2019, oil prices have increased from the December 2018 lows; the average price for oil for the three months ended March 31, 2019 was $54.74 per barrel.

Through the first three quarters of 2018, natural gas prices remained stable, with a nine-month average of approximately $2.94. In November 2018, the monthly average price for natural gas increased to $4.09 per MMBtu, the highest monthly average since November 2014. In the first quarter of 2019, natural gas prices have since declined to levels seen through the majority of 2018; the average price for natural gas for the three months ended March 31, 2019 was $2.83 per MMBtu.

Factors contributing to world-wide commodity pricing volatility 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; actions taken by the Organization of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. 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.

Index

The following table lists average NYMEX prices for oil and natural gas for the three months ended March 31, 2019 and 2018.

	Three Months Ended March 31,				Percent
	2019		2018		Change
Average market closing prices ⁽¹⁾
Oil (per Bbl)	$	54.74	$	62.91		-13.0	%
Natural gas (per Mcf)	$	2.92	$	3.08		-5.2	%

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

The Partnership’s revenues are highly sensitive to changes in oil and natural gas prices and to levels of production. Future growth is dependent on the Partnership’s ability to add reserves in excess of production. Dependent on available cash flow, the Partnership intends to seek opportunities to invest in its existing producing wells, drill new wells on existing leasehold sites like the six wells discussed above drilled in 2018.

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, (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, 2019 and 2018.

	Three Months Ended March 31,
	2019		Percent of Revenue			2018		Percent of Revenue			Percent Change
Total revenues	$	10,091,345		100.0	%	$	13,067,734		100.0	%		-22.8	%
Production expenses		2,818,717		27.9	%		2,934,666		22.5	%		-4.0	%
Production taxes		810,793		8.0	%		1,075,125		8.2	%		-24.6	%
Depreciation, depletion, amortization and accretion		3,433,551		34.0	%		3,967,770		30.4	%		-13.5	%
General, administration and other expense		494,482		4.9	%		381,616		2.9	%		29.6	%

Production (BOE):
Oil		172,705					189,788					-9.0	%
Natural gas		45,788					39,381					16.3	%
Natural gas liquids		43,716					39,360					11.1	%
Total		262,209					268,529					-2.4	%

Average sales price per unit:
Oil (per Bbl)	$	46.85				$	56.09					-16.5	%
Natural gas (per Mcf)		3.50					3.95					-11.4	%
Natural gas liquids (per Bbl)		23.75					37.86					-37.3	%
Combined (per BOE)		38.49					48.66					-20.9	%

Average unit cost per BOE:
Production expenses		10.75					10.93					-1.6	%
Production taxes		3.09					4.00					-22.8	%
Depreciation, depletion, amortization and accretion		13.09					14.78					-11.4	%

Capital expenditures	$	158,117				$	4,593,428

Index

Oil, Natural Gas and NGL Revenues

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. For the three months ended March 31, 2018, revenues for oil, natural gas and NGL sales were $13.1 million. Revenues for the sale of crude oil were $10.6 million, which resulted in a realized price of $56.09 per barrel. Revenues for the sale of natural gas were $0.9 million, which resulted in a realized price of $3.95 per Mcf. Revenues for the sale of NGLs were $1.5 million, which resulted in a realized price of $37.86 per BOE of production.

The Partnership’s results during the first quarter of 2019 were negatively impacted by decreases in commodity prices for oil, natural gas and NGLs, in comparison to the first quarter of 2018. In addition, sold oil production volumes were lower in the first quarter of 2019 when compared to the first quarter of 2018. Sold production for the Sanish Field Assets was approximately 2,915 BOE and 2,985 BOE per day for the three months ended March 31, 2019 and 2018.

Production is dependent on the investment in existing wells and the development of new wells. The Partnership was able to partially offset natural production declines with the 2018 completion of the six wells discussed above. New wells often have high levels of production immediately following completion, then decline to more consistent levels. If the Partnership or its operators are unable or it is not cost beneficial to invest in existing wells or develop new wells, production will decline. See discussion of the Partnership’s anticipated investment in new wells in 2019 below.

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, 2019 and 2018, production expenses were $2.8 million and $2.9 million, respectively, and production expenses per BOE of sold production were $10.75 and $10.93, respectively. Despite a decrease in sold production volumes, the Partnership benefitted from reduced workover expenses during the first quarter of 2019, compared to same period in 2018, which contributed to a reduction in production expenses per BOE of sold production.

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, 2019 and 2018 were $0.8 million (8.0% of revenue) and $1.1 million (8.2% 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, 2019 and 2018 was $3.4 million and $4.0 million, and DD&A per BOE of sold production was $13.09 and $14.78, respectively.

The decrease in 2019 DD&A expense per BOE of production compared to 2018 DD&A expense per BOE of production is primarily due to the increase of the Partnership’s estimated proved undeveloped reserves resulting from changes in the future drill schedule.

Index

General and Administrative Costs

General and administrative costs for the three months ended March 31, 2019 and 2018 was $0.5 million and $0.4 million, respectively. The principal components of general and administrative expense are accounting, legal and consulting fees.

Loss on Derivatives

In December 2017, January 2018 and March 2018, the Partnership entered into derivative contracts (costless collars) with the objective to manage the commodity price risk on a portion of anticipated 2018 oil production. The Partnership’s loss on derivative instruments for the three months ended March 31, 2018 was $1.2 million. The loss is comprised of (i) $0.5 million of losses on settled derivatives during the period, and (ii) $0.7 million of a mark-to-market loss incurred on derivative instruments outstanding at period end. The Partnership’s recognized losses on settled derivatives for the three months ended March 31, 2018 of $0.5 million represented 105,000 barrels of produced oil, resulting in a loss of $4.51 per barrel of oil. The Partnership did not enter into any new derivative contracts during the first quarter of 2019.

Interest Expense

Interest expense, net, for the three months ended March 31, 2019 and 2018 was $0.2 million in both periods, respectively. The primary component of Interest expense, net, during the three-month periods ended March 31, 2019 and 2018 was interest expense on the Credit Facility.

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, 2019 and 2018.

	Three Months Ended March 31, 2019		Three Months Ended March 31, 2018
Net income	$	2,339,974	$	3,325,445
Interest expense, net		193,828		220,857
Depreciation, depletion, amortization and accretion		3,433,551		3,967,770
Exploration expenses		-		-
Non-cash (gain) loss on mark-to-market of derivatives		-		688,677
Adjusted EBITDAX	$	5,967,353	$	8,202,749

Liquidity and Capital Resources

With the completion of the Partnership’s best-efforts offering in April 2017, the Partnership’s principal sources of liquidity are cash on hand, the cash flow generated from properties the Partnership has acquired and availability under the Partnership’s revolving credit facility. As discussed below, the Partnership’s revolving credit facility matures on November 21, 2019. Although the Partnership does not have a commitment from a lender, it anticipates it will be able to refinance its existing credit facility on similar terms prior to maturity and increase its existing commitment to finance planned capital expenditures discussed below. The Partnership anticipates that cash on hand, cash flow from operations and availability under the credit facility will be adequate to meet its anticipated liquidity requirements for at least the next 12 months.

Index

Financing

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

● a maximum leverage ratio

● a minimum current ratio

● maximum distributions

The Partnership was in compliance with the applicable covenants at March 31, 2019.

At March 31, 2019, the outstanding balance on the Credit Facility was $13.8 million.

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

Distributions

For the three months ended March 31, 2019 and 2018, the Partnership paid distributions of $0.349041 and $0.299178 per common unit, or $6.6 million and $5.7 million, respectively. The Partnership generated $5.7 million and $7.1 million, respectively, in cash flow from operating activities for the three months ended March 31, 2019 and 2018. The Partnership’s ability to maintain the current distribution of $1.40 per common unit per year will be based on its ability to increase cash flow from operating activities.

While the Partnership’s goal is to maintain a relatively stable distribution rate over the life of its program, the General Partner monitors monthly Partnership distributions in conjunction with the Partnership’s projected cash requirements for operations, capital expenditures for new wells and debt service.

Index

Oil and Natural Gas Properties

The Partnership incurred approximately $0.2 million and $4.6 million in capital expenditures for the three months ended March 31, 2019 and 2018, respectively. The Partnership expects to invest approximately $35 to $45 million in capital expenditures during 2019, which includes the Partnership’s participation in Whiting’s anticipated 2019 drilling program that consists of Whiting drilling approximately 10 to 20 new wells on the Partnership’s acreage in 2019. The Partnership anticipates Whiting to commence the drilling program in the second quarter of 2019. In addition to Whiting’s 2019 drilling program, the Partnership anticipates that it may be obligated to invest an additional $65 to $70 million in drilling capital expenditures through 2023 to retain its approximate 25-26% working interest in the Sanish Field Assets without becoming subject to non-consent penalties under the joint operating agreements governing the Sanish Field Assets.

Since the Partnership is not the operator of any of its oil and natural gas properties, it is difficult to predict levels of future participation in the drilling and completion of new wells and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast for 2019. Current estimated capital expenditures could be significantly different from amounts actually invested.

The Partnership expects to fund overhead costs and capital additions related to the drilling and completion of wells primarily from cash provided by operating activities, cash on hand and availability under the Credit Facility. As discussed above, the Partnership’s Credit Facility matures on November 21, 2019. Although the Partnership does not have a commitment from a lender, it anticipates it will be able to refinance its existing credit facility on similar terms prior to maturity and increase its existing commitment to finance anticipated capital expenditures. 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.

See further discussion in “Note 6. Related Parties” in Part I, Item 1 of this Form 10-Q.

Subsequent Events

In April 2019, the Partnership declared and paid $2.0 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

Index

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership also 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, 2019 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, 2019 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal controls over financial reporting.

Index

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 2018 Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2018 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
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, 2019 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*

*Filed herewith.

Index

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: May 3, 2019