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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

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FORM 10-Q

  

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

 

For the quarterly period ended March 31, 2017

 

☐	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

 

(Exact name of registrant as specified in its charter)

 

 

(Registrant’s telephone number, including area code)

 

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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.

 

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, 2017, the Partnership had 18,973,474 common units outstanding.

 

Energy 11, L.P.

Form 10-Q

Index

 

 

 

PART I. FINANCIAL INFORMATION

Item 1.  Financial Statements

 

See notes to consolidated financial statements.

See notes to consolidated financial statements.

		Three Months Ended				Three Months Ended
		March 31, 2017				March 31, 2016
Cash flow from operating activities:
Net income (loss)		$	2,621,071			$	(3,592,456	)
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion			3,256,258				2,672,822
Non-cash expenses, net			23,449				1,227,968
Changes in operating assets and liabilities:
Oil, natural gas and natural gas liquids revenue receivable			(2,977,569	)			(2,232,209	)
Other current assets			22,933				-
Accounts payable and accrued expenses			717,514				1,269,228
Net cash flow provided by (used in) operating activities			3,663,656				(654,647	)
Cash flow from investing activities:
Cash paid for acquisition of oil and natural gas properties			(98,327,930	)			-
Additions to oil and natural gas properties			(114,612	)			(241,883	)
Net cash flow used in investing activities			(98,442,542	)			(241,883	)
Cash flow from financing activities:
Net proceeds related to issuance of units			58,504,622				19,857,421
Distributions paid to limited partners			(5,488,149	)			(1,584,847	)
Payments on note payable			(40,000,000	)			(17,000,000	)
Net cash flow provided by financing activities			13,016,473				1,272,574
Increase (decrease) in cash and cash equivalents			(81,762,413	)			376,044
Cash and cash equivalents, beginning of period			86,800,596				3,287,054
Cash and cash equivalents, end of period		$	5,038,183			$	3,663,098
Interest paid		$	158,904			$	906,783
Supplemental non-cash information:
Note payable assumed in Acquisition No. 2			40,000,000				-
Note payable assumed in Acquisition No. 3			33,000,000				-

See notes to consolidated financial statements.

Energy 11, L.P.

Notes to Consolidated Financial Statements

March 31, 2017

 

Note 1.  Partnership Organization

 

Energy 11, L.P. (the “Partnership”) was formed as a Delaware limited partnership. 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 Securities and Exchange Commission (“SEC”) declared the offering effective. The Partnership intended to raise up to $2,000,000,000 of capital, consisting of 100,263,158 common units. As of August 19, 2015, the Partnership completed the sale of the minimum offering of 1,315,790 common units. The subscribers were admitted as Limited Partners of the Partnership at the initial closing of the offering. The Partnership completed its offering on April 24, 2017 with a total of approximately 19.0 million common units sold for gross proceeds of approximately $374.2 million. The proceeds from the sale of the common units have been used to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties.

As of March 31, 2017, the Partnership owns an approximate 26-27% non-operated working interest in 216 existing producing wells and approximately 257 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”), one of the largest producers in the basin, 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. David Lerner Associates, Inc. (the “Dealer Manager”), was the dealer manager for the offering of the common units.

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 2016 Annual Report on Form 10-K. Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2017. 

 

Offering Costs

 

On April 24, 2017, the Partnership completed its best-efforts offering of common units by the Dealer Manager, which received a selling commission and a marketing expense allowance based on proceeds of the common units sold. Additionally, the Partnership incurred other offering costs including legal, accounting and reporting services. These offering costs are recorded by the Partnership as a reduction of partners’ equity. As of March 31, 2017, the Partnership had sold 17.7 million common units for gross proceeds of $348.7 million and proceeds net of offering costs of $325.6 million.

 

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 (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 months ended March 31, 2017 and 2016. 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 6) would occur.

Recently Adopted Accounting Standards

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2017-01, Business Combinations (Topic 805), which amends the existing accounting standards to clarify the definition of a business and assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public entities, the guidance is effective for reporting periods beginning after December 15, 2017, including interim periods within those periods, and should be applied prospectively on or after the effective date. Early application is permitted for transactions that occur before the issuance or effective date of this amendment, provided the transaction has not been reported in financial statements that have been issued or made available for issuance. The Partnership adopted the standard effective January 1, 2017. The Partnership’s acquisitions prior to 2017 were accounted for as acquisitions of an existing business and therefore, all transaction costs were expensed as incurred. The Partnership’s acquisitions in the first quarter of 2017 were accounted for as asset purchases with acquisition costs, such as legal, title and accounting costs, being capitalized as part of the cost of the assets acquired. The Partnership will evaluate any future acquisition(s) of oil and gas properties under the revised standard and account for the acquisition as either an asset purchase or business combination depending on the particular facts and circumstances of the acquisition.

Note 3.  Oil and Natural Gas Investments

On December 18, 2015, the Partnership completed its purchase (“Acquisition No. 1”) of an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. The Partnership accounted for Acquisition No. 1 as a business combination, and therefore expensed, as incurred, transaction costs associated with this acquisition. These costs included, but were not limited to, due diligence, reserve reports, legal and engineering services and site visits.

On January 11, 2017, the Partnership closed on its purchase (“Acquisition No. 2”) of an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $130.0 million, consisting of cash payments totaling $90.0 million and the delivery of a promissory note in favor of the seller of $40.0 million. See Note 4. Notes Payable for further discussion on this promissory note. The Partnership recorded an asset retirement obligation liability of approximately $0.8 million in conjunction with Acquisition No. 2. See Note 5. Asset Retirement Obligations for further discussion.

During the first quarter of 2017, the Partnership and the sellers adjusted the purchase price for the settlement of operating activity that occurred prior to the closing date, which resulted in a net decrease of approximately $1.6 million to the purchase price of the asset. The Partnership accounted for Acquisition No. 2 as a business combination through December 31, 2016; all transaction costs incurred on or prior to December 31, 2016 were expensed as incurred. As discussed above in Note 2, the Partnership adopted ASU 2017-01 on January 1, 2017. Therefore, Acquisition No. 2 was accounted for as an acquisition of a group of assets and transaction costs incurred during the first quarter of 2017 were capitalized, increasing the purchase price of the asset. For the three months ended March 31, 2017, the Partnership capitalized approximately $31,000 of transaction costs related to Acquisition No. 2.

After purchase price adjustments, the Partnership recorded the assets acquired in this transaction at a cost of approximately $128.5 million. Acquisition No. 2 increased the Partnership’s non-operated working interest in the Sanish Field Assets to approximately 22-23%.

On March 31, 2017, the Partnership closed on its purchase (“Acquisition No. 3”) of an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s 216 existing producing wells and 150 of the Partnership’s 257 future development locations in the Sanish Field Assets (“Additional Interest”) for approximately $53.0 million of consideration consisting of cash payments totaling $20.0 million and the delivery of a promissory note in favor of the seller of $33.0 million. See Note 4. Notes Payable for further discussion on this promissory note. The Partnership recorded an asset retirement obligation liability of approximately $0.3 million in conjunction with Acquisition No. 3. See Note 5. Asset Retirement Obligations for further discussion. The purchase was accounted for as an acquisition of a group of assets; as a result, transaction costs were capitalized, increasing the purchase price of the asset. For the three months ended March 31, 2017, the Partnership capitalized approximately $56,000 of transactions costs related to Acquisition No. 3. Acquisition No. 3 increased the Partnership’s total non-operated working interest in the Sanish Field Assets to approximately 26-27%.

The following unaudited pro forma financial information for the three-month periods ended March 31, 2017 and 2016 have been prepared as if Acquisitions No. 2 and No. 3 of the Sanish Field Assets had occurred on January 1, 2016.  The unaudited pro forma financial information was derived from the historical Statement of Operations of the Partnership and the historical information provided by the sellers. The unaudited pro forma financial information does not purport to be indicative of the results of operations that would have occurred had the acquisitions of the Sanish Field Assets and related financings occurred on the basis assumed above, nor is such information indicative of the Partnership’s expected future results of operations.

 

		Three Months ended				Three Months ended
		March 31, 2017				March 31, 2016
		(Unaudited)				(Unaudited)
Revenues		$	12,456,650			$	10,075,232
Net income (loss)		$	2,869,027			$	(3,534,775	)

 

Note 4.  Notes Payable

As part of the financing for Acquisition No. 2, as described above in Note 3. Oil and Natural Gas Investments, on January 11, 2017, the Partnership executed a note in favor of the sellers in the original principal amount of $40.0 million. The Partnership paid the $40.0 million promissory note, which bore interest at 5%, in full on February 23, 2017.

As part of the financing for Acquisition No. 3, as described above in Note 3. Oil and Natural Gas Investments, on March 31, 2017, the Partnership executed a note (“Seller Note”) in favor of the sellers in the original principal amount of $33.0 million. The Seller Note bears interest at 5% per annum and is payable in full no later than August 1, 2017 (“Maturity Date”). There is no penalty for prepayment of the Seller Note. Payment of the Seller Note is secured by a mortgage and liens on the Additional Interest in the Sanish Field Assets in customary form. The first interest payment is due April 30, 2017 and subsequent interest is due on the last day of each month until the Maturity Date. In addition to interest payments on the outstanding principal balance of the Seller Note, the Partnership was required to make a principal payment on or before April 28, 2017 in an amount equal to 100% of the net proceeds the Partnership received from the sale of its equity securities in April 2017. As a result, the Partnership made a principal payment of $24.5 million in April 2017. As of April 30, 2017, the outstanding balance on the Seller Note was $8.5 million. If the Partnership sells any of its owned property, the Partnership is required to make a principal payment equal to 100% of the net proceeds of such sale until the principal amount of the Seller Note is paid in full.

As of March 31, 2017, the outstanding balance on the note was $33.0 million, which approximates its fair market value. The carrying value of all of the other financial instruments of the Partnership approximate fair value due to their short-term nature. The Partnership estimated the fair value of its note payable by discounting the future cash flows of each 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. The market rate, which approximated the Partnership’s interest rate for the Seller Note, takes into consideration general market conditions and maturity.

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:

Note 6.  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, the General Partner received Incentive Distribution Rights (defined below), and has been and will be reimbursed for its documented third party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.

The Partnership completed its best-efforts offering of common units on April 24, 2017. The Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit on August 19, 2015. All subsequent shares of common units were sold at $20.00 per common unit. As of March 31, 2017, the Partnership had completed the sale of 17.7 million common units for total gross proceeds of $348.7 million and proceeds net of selling commissions and marketing expenses of $327.7 million. 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 selling commissions and marketing expenses of $351.8 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 through April 24, 2017, 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; (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, 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; (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest.

For the three months ended March 31, 2017 and 2016, the Partnership paid distributions of $0.349041 and $0.326027 per common unit, or $5.5 million and $1.6 million, respectively.

Note 7.  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 will oversee and review 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.

On July 1, 2016, the Partnership entered into a one-year lease agreement with an affiliate of the General Partner for office space in Oklahoma City, Oklahoma. Under the terms of the agreement, the Partnership will make twelve monthly payments of $8,537. For the three months ended March 31, 2017, the Partnership paid $25,611 to the affiliate of the General Partner.

For the three months ended March 31, 2017 and 2016, approximately $80,000 and $12,000 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, 2017, approximately $71,000 was due to a member of the General Partner.

Glade M. Knight, Chief Executive Officer of the General Partner, and David S. McKenney, Chief Financial Officer of the General Partner, are the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the General Partner of Energy Resources 12, L.P., a newly-formed partnership with the primary investment objective to acquire non-operated working interests in oil and natural gas properties.

Note 8.  Subsequent Events

In April 2017, the Partnership declared and paid $1.7 million, or $0.095890 per outstanding common unit, in distributions to its holders of common units.

In April 2017, the Partnership closed on the issuance of approximately 1.3 million common units through its best-efforts offering, representing gross proceeds to the Partnership of approximately $25.6 million and proceeds net of selling and marketing costs of approximately $24.0 million. As discussed in Note 6. Capital Contribution and Partners’ Equity, the offering was completed on April 24, 2017.

In April 2017, the Partnership made a principal payment of $24.5 million on its note payable issued as part of the purchase price in Acquisition No. 3, which is described in Note 4. Notes Payable. As of April 30, 2017, the outstanding balance on the note was $8.5 million.

E11 Incentive Holdings, LLC (“Incentive Holdings”) was the owner of all Class B units outstanding (62,500) as of March 31, 2017. Since March 31, 2017, Incentive Holdings has transferred substantially all of its assets; on April 5, 2017, Incentive Holdings transferred 18,125 of the 62,500 Class B units to E11 Incentive Carry Vehicle, LLC, an affiliate of Incentive Holdings, for de minimis consideration. On April 6, 2017, the remaining 44,375 Class B units were acquired by Regional Energy Incentives, LP in exchange for approximately $98,000. Regional Energy Incentives, LP is owned by entities that are controlled by Anthony F. Keating, III, Co-Chief Operating Officer of the General Partner, Michael J. Mallick, Co-Chief Operating Officer of the General Partner, and David S. McKenney, Chief Financial Officer of the General Partner. The Class B units entitle the holder to certain distribution rights after Payout, as described in Note 6. Capital Contribution and Partners’ Equity.

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:

 

 

These forward-looking statements reflect the Partnership’s current beliefs and expectations with respect to future events and are based on assumptions and are subject to risks and uncertainties and other factors outside the Partnership’s control that may cause actual results to differ materially from those projected. Such factors include, but are not limited to, those described under “Risk Factors” and the following:

 

 

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, 2016.

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 intended to raise up to $2,000,000,000 of capital, consisting of 100,263,158 common units. As of August 19, 2015, the Partnership completed the sale of the minimum offering of 1,315,790 common units for gross proceeds of $25 million. Upon raising the minimum offering amount, the holders of the common units were admitted and the Partnership commenced operations. 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 selling commissions and marketing expenses of $351.8 million.

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 location in Mountrail County, North Dakota, acquiring an approximate 11% non-operated working interest in approximately 215 existing producing wells and approximately 257 future development locations (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 216 existing producing wells and 150 of the Partnership’s 257 future development locations in the Sanish Field Assets for approximately $53.0 million.

As a result of these acquisitions, as of March 31, 2017, the Partnership has an approximate 26-27% non-operated working interest in the Sanish Field Assets, consisting of 216 existing producing wells and 257 future development locations. Substantially all of the Partnership’s assets are managed and operated by Whiting Petroleum Corporation (“Whiting”), a publicly traded oil and gas company.

The Sanish Field Assets are a part of the Bakken shale formation in the Greater Williston Basin. The Bakken Shale is one of the largest oil fields in the U.S.

Current Price Environment

Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control. Historically, energy commodity prices have been volatile; oil prices declined throughout 2015 and in the first quarter of 2016, prices had fallen to the lowest levels since October 2003. Commodity prices increased to 52-week highs by February 2017, but due to geopolitical risks in oil producing regions of the world as well as global supply and demand concerns, the Partnership continues to expect significant price volatility. 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.

The following table lists average NYMEX prices for oil and natural gas for the three months ended March 31, 2017 and 2016.

(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 production wells via capital expenditures and/or drill new wells on existing leasehold sites.

Results of Operations

In evaluating financial condition and operating performance, the most important indicators on which the Partnership focuses are (1) total quarterly 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, 2017 and 2016. The results for the three months ended March 31, 2017 and 2016 include results from each of the Partnership’s acquisitions for the periods owned. Since the three months ended March 31, 2016 includes only Acquisition No. 1, the operating results are not comparable.

Oil, Natural Gas and NGL Sales

 

For the three months ended March 31, 2017, revenues for oil, natural gas and NGL sales were $10.1 million. Revenues for the sale of crude oil were $8.4 million, which resulted in a realized price of $45.74 per barrel. Revenues for the sale of natural gas were $0.7 million, which resulted in a realized price of $3.56 per Mcf. Revenues for the sale of NGLs were $1.0 million, which resulted in a realized price of $30.03 per BOE of production. For the three months ended March 31, 2016, revenues for oil, natural gas and NGL sales were $4.3 million. Revenues for the sale of crude oil were $3.9 million, which resulted in a realized price of $26.84 per barrel. Revenues for the sale of natural gas were $0.2 million, which resulted in a realized price of $1.69 per Mcf. Revenues for the sale of NGLs were $0.2 million, which resulted in a realized price of $7.78 per BOE of production.

In comparison to the first quarter of 2016, the Partnership benefited from significant increases in commodity prices for oil, natural gas and NGLs during the first quarter of 2017, as market prices rebounded from market lows experienced during the first quarter of 2016. Price gains were partially offset by the natural decline in production from existing wells, as the Partnership did not start or complete any new wells during the three months ended March 31, 2017. Production for the interest acquired in Acquisition No. 1, which was owned for the entire periods presented was 1,454 BOE per day and 2,068 BOE per day for the three months ended March 31, 2017 and 2016. Production for the remainder of 2017 will be dependent on the investment in existing wells and the development of new wells. If the Partnership or its operator is unable or it is not cost beneficial to invest in existing wells or develop new wells, production will decline.

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.

For the three months ended March 31, 2017 and 2016, production expenses were $2.7 million and $1.4 million, respectively, and production expenses per BOE of production were $10.92 and $7.20, respectively. The increase in the first quarter of 2017 compared to the first quarter of 2016 is due primarily to the following factors: (a) approximately 15 of the Partnership’s wells required substantial rework, resulting in an increase in workover expenses of $0.5 million from the first quarter of 2016; (b) during the third quarter of 2016, the Partnership’s operator amended its gathering and processing contract, which has led to increases in certain gathering and processing costs subsequent to the amendment date; and (c) higher third-party fractionation expenses and plant processing costs. In addition, production expenses per BOE of production have increased due to natural production volume declines as reservoirs are depleted.

Production Taxes

North Dakota’s oil tax structure is comprised of two main taxes: the production tax and the extraction tax. The production tax is 5%. Beginning January 1, 2016, the extraction tax rate is also 5% of the gross value at the well. This rate can increase to 6% if the high-price trigger, defined as the average price of a barrel of oil exceeding a trigger price of $90 for each month in any consecutive three-month period, is in effect. The 6% rate would remain in effect until the average price is less than $90 per barrel for each month in any consecutive three-month period.

The production tax on gas is subject to a price index change on July 1 of each calendar year. The rate for July 1, 2016 through June 30, 2017 is $0.0601 per Mcf. The previous rate from July 1, 2015 through June 30, 2016 was $0.1106 per Mcf.

Production taxes for the three months ended March 31, 2017 and 2016 were $0.9 million (8% of revenue) and $0.4 million (10% of revenue), respectively.

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, 2017 and 2016 was $3.3 million and $2.7 million, and DD&A per BOE of production was $13.01 and $14.20, respectively. The decrease in DD&A expense per BOE of production is primarily the result of the increase of the Partnership’s estimated reserves compared to the purchase price in conjunction with Acquisitions No. 2 and No. 3.

Management Fees

Fees and expenses incurred under the Management Agreement with the Partnership’s former manager for the three months ended March 31, 2016 were $0.9 million. The Management Agreement was terminated in April 2016.

General and Administrative Costs

General and administrative costs for the three months ended March 31, 2017 and 2016 were $0.5 million and $0.4 million, respectively. The principal components of general and administrative expense are accounting, legal and consulting fees. The increase in the first quarter of 2017 compared to the first quarter of 2016 is due primarily to the increase in assets owned by the Partnership and the increase in limited partners.

Supplemental Non-GAAP Measure

The Partnership uses “EBITDAX”, defined as Earnings before Interest, Income Taxes, Depreciation, Depletion, Amortization and Exploration Expenses, as a key supplemental measure of its operating performance. This non-GAAP financial measure should be considered along with, but not as an alternative to, net income (loss), operating income (loss), cash flow from operating activities or other measures of financial performance presented in accordance with GAAP. EBITDAX is not necessarily indicative of funds available to fund the Company’s cash needs, including its ability to make cash distributions. Although EBITDAX, as calculated by the Partnership, may not be comparable to EBITDAX as reported by other companies that do not define such term exactly as the Partnership defines such term, 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 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 operator.

The following table reconciles the Partnership’s GAAP net income (loss) to EBITDAX for the three ended March 31, 2017 and 2016.

Liquidity and Capital Resources

With the completion of the Partnership’s best-efforts offering in April 2017, the Partnership’s principal source of liquidity will be cash on hand and the cash flow generated from properties the Partnership has acquired. The Partnership anticipates that cash on hand and cash flow from operations will be adequate to meet its anticipated liquidity requirements. In addition, the Partnership may borrow funds to pay operating expenses, make distributions, refinance outstanding debt or for other capital needs of the Partnership.

Financing

The Partnership entered into a promissory note in January 2017 in conjunction with Acquisition No. 2 in an original principal amount of $40.0 million. The Partnership paid off this note on February 23, 2017 using equity proceeds raised from its best-efforts offering in 2017. See further discussion in “Note 4. Notes Payable” in Part I, Item 1 of this Form 10-Q.

As part of the financing for Acquisition No. 3, the Partnership executed a promissory note in favor of the sellers in the original principal amount of $33.0 million. The note bears interest at 5% per annum and is payable in full no later than August 1, 2017. In April 2017, with proceeds from the final closing under its best-efforts offering, the Partnership repaid $24.5 million of the outstanding balance of this note. The Partnership anticipates obtaining a credit facility or using cash on hand and cash flow from operations to repay the remaining note balance of $8.5 million. The Partnership expects that a credit facility would be secured by a mortgage on its assets and/or that credit facility would provide for borrowings up to a borrowing base to be set by the lenders, at their discretion, based in part upon the lenders’ valuation of the Partnership’s reserves. Additionally, a credit facility may contain covenants requiring, among others, a minimum net worth or maximum distributions. If the Partnership cannot repay the note, it may be in default and be required to reduce distributions.

Partners Equity 

The Partnership completed its best-efforts offering of common units on April 24, 2017. The Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit on August 19, 2015. All subsequent shares of common units were sold at $20.00 per common unit. As of March 31, 2017, the Partnership had completed the sale of 17.7 million common units for total gross proceeds of $348.7 million and proceeds net of selling commissions and marketing expenses of $327.7 million. 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 selling commissions and marketing expenses of $351.8 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 through April 24, 2017, the total contingent fee is a maximum of approximately $15.0 million, which will only be paid if Payout occurs, as defined in “Note 6. Capital Contribution and Partners’ Equity” in Part I, Item 1 of this Form 10-Q.

Distributions

For the three months ended March 31, 2017 and 2016, the Partnership made distributions of $0.349041 and $0.326027 per common unit, or $5.5 million and $1.6 million, respectively. The Partnership generated $3.7 million in cash flow from operations for the three months ended March 31, 2017.

Since a portion of distributions to date have been funded with proceeds from the offering of common units, the Partnership’s ability to maintain its current rate of distribution ($1.40 per unit per year) will be based on its ability to increase its cash generated from operations.  As there can be no assurance that the Partnership’s current assets will provide income at this level, there can be no assurance as to the classification or duration of distributions at the current rate.  Proceeds of the offering which are distributed are not available for investment in properties.

Oil and Natural Gas Properties

The Partnership incurred approximately $0.2 million in capital expenditures for the three months ended March 31, 2017. The Partnership incurred approximately $1.0 million in capital expenditures for the three months ended March 31, 2016.

The Partnership expects to invest an additional $6.0 to $9.0 million in capital expenditures during 2017, which includes drilling and completion of approximately two to five new wells. If oil, natural gas and NGL prices during 2017 are not at levels that make it cost beneficial to drill and complete new wells, the Partnership expects to invest approximately $1.5 to $3.0 million in capital expenditures in 2017. The capital expenditure plan has the flexibility to adjust should the commodity price environment change. A decrease in oil, natural gas and NGL prices will lead to a reduction in capital expenditures and lower oil, NGL and natural gas production volumes.

 

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 the remainder of 2017 and 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 a credit facility.

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 will oversee and review 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 7. Related Parties” in Part I, Item 1 of this Form 10-Q.

Subsequent Events

In April 2017, the Partnership declared and paid $1.7 million, or $0.095890 per outstanding common unit, in distributions to its holders of common units.

In April 2017, the Partnership closed on the issuance of approximately 1.3 million common units through its best-efforts offering, representing gross proceeds to the Partnership of approximately $25.6 million and proceeds net of selling and marketing costs of approximately $24.0 million. As discussed in Note 6. Capital Contribution and Partners’ Equity in Part I, Item 1 of this Form 10-Q, the offering was completed on April 24, 2017.

In April 2017, the Partnership made a principal payment of $24.5 million on its note payable issued as part of the purchase price in Acquisition No. 3. As of April 30, 2017, the outstanding balance on the note was $8.5 million.

E11 Incentive Holdings, LLC (“Incentive Holdings”) was the owner of all Class B units outstanding (62,500) as of March 31, 2017. Since March 31, 2017, Incentive Holdings has transferred substantially all of its assets; on April 5, 2017, Incentive Holdings transferred 18,125 of the 62,500 Class B units to E11 Incentive Carry Vehicle, LLC, an affiliate of Incentive Holdings, for de minimis consideration. On April 6, 2017, the remaining 44,375 Class B units were acquired by Regional Energy Incentives, LP in exchange for approximately $98,000. Regional Energy Incentives, LP is owned by entities that are controlled by Anthony F. Keating, III, Co-Chief Operating Officer of the General Partner, Michael J. Mallick, Co-Chief Operating Officer of the General Partner, and David S. McKenney, Chief Financial Officer of the General Partner. The Class B units entitle the holder to certain distribution rights after Payout, as described in Note 6. Capital Contribution and Partners’ Equity. 

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

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, 2017 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, 2017 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal controls over financial reporting.

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 2016 Form 10-K.  There have been no material changes to the risk factors previously disclosed in the 2016 Form 10-K.

 

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

 

Common Units

The Partnership’s Registration Statement on Form S-1 (File No. 333-197476) was declared effective by the Securities and Exchange Commission on January 22, 2015. Under the public offering we made under the Registration Statement (as amended and supplemented), we offered common units of limited partner interest (the “common units”) on a best-efforts basis with the intention of raising up to $2,000,000,000 of capital, consisting of 100,263,158 common units. As of March 31, 2017, the Partnership had completed the sale of 17,695,945 common units for total gross proceeds of $348.7 million and proceeds net of offering costs including selling commissions and marketing expenses of $325.6 million. As of March 31, 2017, 82,567,213 common units remained unsold. The Partnership’s offering of common units of limited partner interest was completed on April 24, 2017. Upon completion, the Partnership had sold approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of selling commissions and marketing expenses of $351.8 million.

Under the Partnership’s 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 may 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 April 24, 2017, the total contingent fee is a maximum of approximately $15.0 million.

There is currently no established public trading market in which the Partnership’s common units are traded. The net proceeds of the public offering were used as follows:

Use of Proceeds

The following tables set forth information concerning the on-going best-efforts offering and the use of proceeds from the offering as of March 31, 2017.

Item 3.  Defaults upon Senior Securities.

 

Not applicable.

 

Item 4.  Mine Safety Disclosures.

 

Not applicable.

 

Item 5.  Other Information.

 

Not applicable.

 

Item 6.  Exhibits.

 

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*Filed herewith.

 

 

 

 

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 12, 2017