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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 June 30, 2018

 

☐	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 000-55916

 

Energy Resources 12, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware	81-4805237
(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)

 

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.

 

Large accelerated filer   ☐		Accelerated filer ☐
Non-accelerated filer     ☐ (Do not check if a smaller reporting company)		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 July 31, 2018, the Partnership had 5,578,765 common units outstanding.

 

 

Energy Resources 12, L.P.

Form 10-Q

Index

 

			Page Number
PART I.  FINANCIAL INFORMATION
	Item 1.	Consolidated Financial Statements (Unaudited)
		Consolidated Balance Sheets – June 30, 2018 and December 31, 2017	3
		Consolidated Statements of Operations – Three and six months ended June 30, 2018 and 2017	4
		Consolidated Statements of Cash Flows – Six months ended June 30, 2018 and 2017	5
		Notes to Consolidated Financial Statements	6
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	19
	Item 4.	Controls and Procedures	19
PART II.  OTHER INFORMATION
	Item 1.	Legal Proceeding	20
	Item 1A.	Risk Factors	20
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	20
	Item 3.	Defaults upon Senior Securities	21
	Item 4.	Mine Safety Disclosures	21
	Item 5.	Other Information	21
	Item 6.	Exhibits	22
Signatures			23

 

 

 

PART I. FINANCIAL INFORMATION

 

Item 1.  Financial Statements

 

Energy Resources 12, L.P.

Consolidated Balance Sheets

(Unaudited)

 

		June 30,				December 31,
		2018				2017
Assets
Cash and cash equivalents		$	11,881,132			$	46,859,728
Oil, natural gas and natural gas liquids revenue receivable			3,881,168				-
Deposit for potential acquisition			4,125,000				8,750,000
Deferred acquisition costs			4,125,981				4,884,208
Total Current Assets			24,013,281				60,493,936
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $2,013,028 and $0, respectively			91,234,376				-
Total Assets		$	115,247,657			$	60,493,936
Liabilities
Term loan		$	15,000,000			$	-
Due to related parties			4,474,698				5,283,623
Accounts payable and accrued expenses			1,616,021				164,786
Total Current Liabilities			21,090,719				5,448,409
Asset retirement obligations			141,768				-
Total Liabilities			21,232,487				5,448,409
Partners’ Equity
Limited partners' interest (5,157,398 and 3,191,231 common units issued and outstanding, respectively)			94,015,385				55,045,742
General partner's interest			(215	)			(215	)
Total Partners’ Equity			94,015,170				55,045,527
Total Liabilities and Partners’ Equity		$	115,247,657			$	60,493,936

 

See notes to consolidated financial statements.

 

 

Energy Resources 12, L.P.

Consolidated Statements of Operations

(Unaudited)

 

		Three Months Ended				Three Months Ended				Six Months Ended				Six Months Ended
		June 30, 2018				June 30, 2017				June 30, 2018				June 30, 2018
Revenue
Oil, natural gas and natural gas liquids revenues		$	7,531,096			$	-			$	11,028,175			$	-
Operating costs and expenses
Production expenses			1,635,724				-				2,268,627				-
Production taxes			617,248				-				938,526				-
General and administrative expenses			343,745				14,845				744,034				21,105
Depreciation, depletion, amortization and accretion			1,321,361				-				2,016,079				-
Total operating costs and expenses			3,918,078				14,845				5,967,266				21,105
Operating income			3,613,018				(14,845	)			5,060,909				(21,105	)
Interest expense, net			(212,483	)			(830	)			(372,049	)			(1,105	)
Net income (loss)		$	3,400,535			$	(15,675	)		$	4,688,860			$	(22,210	)
Basic and diluted net income per common unit		$	0.82							$	1.24
Weighted average common units outstanding - basic and diluted			4,158,589								3,795,001

 

See notes to consolidated financial statements.

 

 

Energy Resources 12, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

 

		Six Months Ended				Six Months Ended
		June 30, 2018				June 30, 2017
Cash flow from operating activities:
Net income (loss)		$	4,688,860			$	(22,210	)
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion			2,016,079				-
Changes in operating assets and liabilities:
Oil, natural gas and natural gas liquids revenue receivable			(4,427,059	)			-
Due to related parties			(208,925	)			-
Accounts payable and accrued expenses			1,069,593				18,668
Net cash flow provided by (used in) operating activities			3,138,548				(3,542	)
Cash flow from investing activities:
Cash paid for acquisition of oil and natural gas properties			(81,696,819	)			-
Deposit for potential acquisition of oil and natural gas properties			(4,125,000	)			-
Additions to oil and natural gas properties			(1,571,696	)			-
Net cash flow used in investing activities			(87,393,515	)			-
Cash flow from financing activities:
Cash paid for offering costs			-				(224,608	)
Net proceeds from line of credit			-				229,000
Proceeds from term loan			25,000,000				-
Payments on term loan			(10,000,000	)			-
Proceeds from advance from member of general partner			7,000,000				-
Payments on advance from member of general partner			(7,000,000	)			-
Net proceeds related to issuance of units			36,908,195				-
Distributions paid to limited partners			(2,631,824	)			-
Net cash flow provided by financing activities			49,276,371				4,392
Increase (decrease) in cash and cash equivalents			(34,978,596	)			850
Cash and cash equivalents, beginning of period			46,859,728				1,000
Cash and cash equivalents, end of period		$	11,881,132			$	1,850
Interest paid		$	397,954			$	679
Supplemental non-cash information:
Accrued deferred offering costs			-				258,683

 

See notes to consolidated financial statements.

 

 

Energy Resources 12, L.P.

Notes to Consolidated Financial Statements

June 30, 2018

(Unaudited)

 

Note 1.  Partnership Organization

 

Energy Resources 12, L.P. (together with its wholly-owned subsidiary, the “Partnership”) was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership is offering common units of limited partner interest (the “common units”) on a best-efforts basis with the intention of raising up to $350,000,001 of capital, consisting of 17,631,579 common units. The Partnership’s offering was declared effective by the Securities and Exchange Commission (“SEC”) on May 17, 2017. As of July 25, 2017, the Partnership completed the sale of the minimum offering of 1,315,790 common units. The subscribers to the common units were admitted as Limited Partners of the Partnership at the initial closing of the offering and the Partnership has been admitting additional Limited Partners monthly since that time.

 

The Partnership’s primary investment objectives are to (i) acquire producing and non-producing oil and gas properties with development potential to be operated by third-party operators, and to enhance the value of the properties through drilling and other development activities, (ii) make distributions to the holders of the common units, (iii) engage in a liquidity transaction after five to seven years, in which all properties are sold and the sales proceeds are distributed to the partners, merge with another entity, or list the common units on a national securities exchange, and (iv) permit holders of common units to invest in oil and gas properties in a tax efficient basis. The proceeds from the sale of the common units primarily will be used to acquire producing and non-producing oil and natural gas properties onshore in the United States, and to develop those properties.

 

As of June 30, 2018, the Partnership owned an approximate 2.7% non-operated working interest in 240 currently producing wells and 19 wells in various stages of the drilling and completion process, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 14 third-party operators on behalf of the Partnership and other working interest owners.

 

The general partner of the Partnership is Energy Resources 12 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. David Lerner Associates, Inc. (the “Managing Dealer”), is acting as 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 for complete financial statements. 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 December 31, 2017 financial statements included in its 2017 Annual Report on Form 10-K. Operating results for the three and six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2018. 

 

Cash and Cash Equivalents

 

Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.

 

Offering Costs

 

The Partnership is raising capital through an on-going best-efforts offering of units by the Managing Dealer, which receives a selling commission and a marketing expense allowance based on proceeds of the units sold. Additionally, the Partnership has 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 June 30, 2018, the Partnership had completed the sale of 5.2 million common units for gross proceeds of approximately $100.5 million and proceeds net of offering costs of approximately $93.9 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.

 

The Partnership does not operate its oil and natural gas properties and receives actual oil, natural gas and natural gas liquids (“NGL”) sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. The Partnership closed on its first property acquisition on February 1, 2018 and continues to complete the requisite division and transfer orders to obtain title for each well with each operator. As a result, the operational data received from the operators during the post-close process is preliminary. Therefore, the Partnership has used the most current available production data gathered from its operators and the Oil and Gas Division of the North Dakota Industrial Commission, and oil, natural gas and NGL national index prices are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined or the settlement proceeds are received.

 

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 and six months ended June 30, 2018. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 6) are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 6) would occur.

 

Revenue Recognition

 

Since it did not acquire any assets until 2018, the Partnership did not record any revenue in 2017. The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. Settlement receipts for sales of oil, natural gas and natural gas liquids may not be received for more than a month after the date production is delivered to the purchaser, and as a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Partnership records the differences between estimates and the actual amounts received for product sales in the month that settlement proceeds are received from the operator.

 

The following table disaggregates the Partnership’s revenue streams that are summarized as “Oil, natural gas and natural gas liquids revenues” on the consolidated statements of operations for the three and six months ended June 30, 2018.

 

		Three Months Ended June 30, 2018				Six Months Ended June 30, 2018
Oil revenues		$	7,018,563			$	10,207,973
Natural gas revenues			292,454				375,607
Natural gas liquids revenues			220,079				444,595
		$	7,531,096			$	11,028,175

 

 

Recently Adopted Accounting Standards

 

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting model to enable entities to better portray their risk management activities in their financial statements and enhance the transparency and understandability of hedging activity. The standard simplifies the application of hedge accounting and reduces the administrative burden of hedge documentation requirements and assessing hedge effectiveness. The standard is effective for annual and interim periods beginning after December 15, 2018 with early adoption permitted. The standard requires a modified retrospective approach for all hedge relationships that exist on the date of adoption. The presentation and disclosure guidance is required only prospectively. The Partnership adopted this standard on January 1, 2018. As of January 1, 2018 and June 30, 2018, the Partnership did not have any outstanding hedge positions; therefore, the adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements.

 

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606), that amends the former revenue recognition guidance and provides a revised comprehensive revenue recognition model with customers that contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. Throughout 2016 and 2017, the FASB issued several updates, including ASUs 2016-08, 2016-10, 2016-12, 2016-20, 2017-13 and 2017-14, respectively, to clarify specific topics originally described in ASU 2014-09. In August 2015, the FASB issued ASU No. 2015-14, which deferred the effective date of ASU 2014-09 to annual and interim periods beginning after December 15, 2017, and permitted early application for annual reporting periods beginning after December 15, 2016. The Partnership adopted this standard on January 1, 2018. The Partnership did not recognize any revenue for any period prior to adoption of this standard.

 

Recently Issued Accounting Standards

 

In February 2016, the FASB issued 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 standard is effective for annual and interim periods beginning after December 15, 2018 with early adoption permitted. The Partnership expects to adopt this standard as of January 1, 2019. Although the Partnership has not yet identified any material impact, the Partnership is still evaluating the impact this standard will have on its consolidated financial statements and related disclosures. 

 

Note 3.  Oil and Gas Investments

 

On February 1, 2018, the Partnership completed its purchase of the Bakken Assets for $87.5 million. In addition to using proceeds from its best-efforts offering, the Partnership partially funded the acquisition using proceeds from an unsecured term loan of $25.0 million (discussed below in Note 5. Debt) and an advance from a member of the General Partner of $7.0 million. The advance from a member of the General Partner was repaid in full in May 2018. At closing, the Bakken Assets were comprised of 204 producing wells and 30 wells in various stages of the drilling and completion process.

 

The Partnership accounted for this acquisition as a purchase of a group of similar assets, and therefore capitalized transaction costs associated with this acquisition. These acquisition-related costs included, but were not limited to, fees for advisory and consulting (discussed below), due diligence, legal, accounting, engineering and environmental review services. The Partnership has capitalized approximately $5.0 million in transaction costs in conjunction with the acquisition. The Partnership also recorded an asset retirement obligation liability of approximately $0.1 million in conjunction with this acquisition. See Note 4. Asset Retirement Obligation below.

 

The Partnership adjusted the purchase price to reflect the operating revenues and expenses of the Bakken Assets between the acquisition effective date of September 1, 2017 and the closing date of February 1, 2018, in accordance with the closing conditions set forth in the purchase agreement. The net impact of the purchase price adjustments was a decrease to the purchase price of the asset of approximately $2.3 million.

 

The Partnership engaged Regional Energy Investors, LP (“REI”) to perform advisory and consulting services, including supporting the Partnership through closing and post-closing of the purchase agreement of the Bakken Assets. In the first quarter of 2018, the Partnership paid REI a total of approximately $5.3 million for its advisory and consulting services. REI is also entitled to a fee of 5% of the gross sales price in the event the Partnership disposes any or all of the Bakken Assets, if surplus funds are available after Payout to the holders of the Partnership’s common units, as defined in Note 6 below. Of the $5.3 million paid to REI, approximately $4.7 million of these services related to the acquisition of the Bakken Assets have been capitalized as part of the acquisition costs described above. REI is owned by entities that are controlled by Anthony F. Keating, III, Co-Chief Operating Officer of Energy 11 GP, LLC, and Michael J. Mallick, Co-Chief Operating Officer of Energy 11 GP, LLC. Glade M. Knight and David S. McKenney are the Chief Executive Officer and Chief Financial Officer, respectively, of Energy 11 GP, LLC as well as the Chief Executive Officer and Chief Financial Officer, respectively, of the General Partner. See Note 7. Related Parties below for additional information.

 

 

In total, the Partnership incurred approximately $2.9 million in capital drilling and completion costs for the period from February 1, 2018 to June 30, 2018. From February 1, 2018 to June 30, 2018, the Partnership participated in the drilling of 55 wells, of which 36 have been completed and 19 wells are in various stages of completion at June 30, 2018. To date, the Partnership has incurred approximately $2.9 million in capital expenditures and anticipates approximately $0.7 million remain to complete the 19 wells in various stages of completion.

 

The following unaudited pro forma financial information for the three and six months ended June 30, 2018 and 2017 have been prepared as if the acquisition of the Bakken Assets had occurred on January 1, 2017. The unaudited pro forma financial information was derived from the historical statements of operations of the Partnership and the historical financial statements of the sellers of the Bakken Assets. The unaudited pro forma financial information does not purport to be indicative of the results of operations that would have occurred had the acquisition of the Bakken 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 June 30, 2018				Three Months Ended June 30, 2017				Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
Revenues		$	7,531,096			$	3,423,571			$	12,729,593			$	6,262,434
Net income		$	3,475,952			$	1,057,017			$	5,664,109			$	1,938,596

 

On June 29, 2018, the Partnership, through a wholly-owned subsidiary (the “Buyer”), entered into a Purchase and Sale Agreement (“Purchase Agreement No. 2”) with Bruin E&P Non-Op Holdings, LLC (“Seller”), for the potential purchase of an additional portion of the Seller’s interest in the Bakken Assets, resulting in the Partnership acquiring an additional approximate average 2.7% non-operated working interest (the “Target Assets”). If all conditions to closing on the Target Assets are met under the Purchase Agreement No. 2, the Partnership’s non-operated working interest in the Bakken Assets would increase to approximately a total of 5.4%.

 

Pursuant to Purchase Agreement No. 2, the purchase price for the Target Assets is $82.5 million, subject to customary adjustments. On June 29, 2018, the Partnership funded a deposit of 5% of the purchase price, or $4,125,000 (the “Deposit”), to the Seller to be applied toward the purchase price at closing or to be released to the Seller if the transaction does not close by the outside closing date due to the Buyer’s breach of Purchase Agreement No. 2. In the event the transaction does not close due to a breach by Sellers, the Deposit will be refunded to the Partnership. If the Buyer does not perform under the contract as a result of its diligence review or otherwise breach Purchase Agreement No. 2, the Sellers’ sole remedy against the Buyer is release of the Deposit to the Seller. The final settlement purchase price is subject to customary post-closing adjustments, as defined and identified in Purchase Agreement No. 2.

 

The closing of Purchase Agreement No. 2 is subject to the satisfaction of a number of required conditions which currently remain unsatisfied under Purchase Agreement No. 2. Consummation of the acquisition is subject to the Buyer’s satisfactory completion of the review of title, environmental investigations, financial analysis and geological analysis, obtaining sufficient financing to fund the purchase price and other due diligence. Accordingly, there can be no assurance at this time that all of the conditions precedent to consummating Purchase Agreement No. 2 will be satisfied, that the Partnership will find the results of its diligence investigation acceptable, that the Partnership will be able to obtain sufficient financing on terms reasonably acceptable or that the transaction will be successfully completed.

 

The Partnership has engaged REI to perform advisory and consulting services and support the Partnership through closing of Purchase Agreement No. 2, including assistance with due diligence related to the Target Assets and obtaining financing for the proposed transaction. The Partnership will pay REI a total of approximately $4.1 million for its advisory and consulting services; the $4.1 million has been accrued in Due to related parties on the consolidated balance sheets as of June 30, 2018. REI is also entitled to a fee of 5% of the gross sales price in the event the Partnership disposes any or all of the Target Assets, if surplus funds are available after Payout to the holders of the Partnership’s common units, as defined below in Note 6.

 

 

Note 4.  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:

 

		2018
Balance as of January 1, 2018		$	-
Liabilities incurred on February 1, 2018 (acquisition)			133,155
Well additions			5,562
Accretion			3,051
Balance as of June 30, 2018		$	141,768

 

Note 5.  Debt

 

On January 16, 2018, the Partnership entered into a loan agreement with Bank of America, N.A., as the lender, for an unsecured term loan (“Term Loan”) of $25.0 million. The Partnership used the $25.0 million proceeds from the Term Loan to partially fund the initial purchase of the Bakken Assets, as described in Note 3. Oil and Gas Investments above. The Term Loan bears interest at a variable rate based on the London Inter-Bank Offered Rate (LIBOR) plus a margin of 2.00%. Interest is payable monthly. The maturity date is January 15, 2019.

 

The Term Loan contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Under the terms of the loan agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. Glade M. Knight, the General Partner’s Chief Executive Officer, and David S. McKenney, the General Partner’s Chief Financial Officer, have guaranteed repayment of the Term Loan and have not and will not receive any consideration in exchange for providing this guarantee.

 

As of June 30, 2018, the outstanding balance on the Term Loan was $15.0 million. The outstanding balance at June 30, 2018 approximates its fair market value. The Partnership estimated the fair value of its Term Loan 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.

 

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.

 

As of July 25, 2017, the Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit. In October 2017, the Partnership completed the sale of all common units at $19.00 (2,631,579 common units). In accordance with the prospectus, all subsequent common units are being sold at $20.00 per common unit. As of June 30, 2018, the Partnership had completed the sale of 5.2 million common units for gross proceeds of approximately $100.5 million and proceeds net of offering costs of approximately $93.9 million.

 

The Partnership intends to continue to raise capital through its best-efforts offering of common units by the Managing Dealer at $20.00. Under the agreement with the Managing Dealer, the Managing Dealer receives a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through June 30, 2018, the Dealer Manager Incentive Fees are approximately $4.0 million, subject to Payout (defined below).

 

 

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 and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.

 

The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, 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 common unit, regardless of the amount paid for the common 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, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

 

●	Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

 

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

 

For the three and six months ended June 30, 2018, the Partnership paid distributions of $0.349041 and $0.698082 per common unit, or $1.4 million and $2.6 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 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.

 

The Partnership will reimburse the General Partner for any costs incurred by the General Partner for certain expenses, which include costs for organizing the Partnership and costs incurred in the offering of the common units. The Partnership has also agreed to pay the General Partner an advisory fee to manage the day-to-day affairs of the Partnership, including serving as an investment advisor and consultant in connection with the acquisition, development, operation and disposition of oil and gas properties and other assets of the Partnership. In accordance with the limited partner agreement, subsequent to the Partnership’s first asset purchase which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. Based upon the total gross equity proceeds as of June 30, 2018, the management fee for the three and six months ended June 30, 2018 due to the General Partner is approximately $126,000 and $185,000, respectively. As of June 30, 2018, the accrued management fee due to the General Partner is approximately $185,000, which has been accrued on the consolidated balance sheets in Due to related parties at June 30, 2018 and included in General and administrative expenses on the consolidated statements of operations.

 

The Partnership also will reimburse the General Partner for certain general and administrative costs. For the three and six months ended June 30, 2018, approximately $102,000 and $183,000 of general and administrative costs were incurred by a member of the General Partner and will be reimbursed by the Partnership. At June 30, 2018, the approximately $102,000 that was due to a member of the General Partner is included in Due to related parties in the consolidated balance sheets.

 

In January 2018, the Partnership received an advance of $7.0 million from a member of the General Partner to partially fund the purchase of the Bakken Assets. The Partnership repaid a member of the General Partner in full in May 2018. The advance did not bear interest and the member of the General Partner did not receive any compensation for the advance.

 

 

The Chief Executive Officer and Chief Financial Officer of the Partnership’s General Partner are also the Chief Executive Officer and Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, L.P. (“Energy 11”), 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 Energy 11 that will give the Partnership access to Energy 11’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The shared day-to-day costs will be split evenly between the two partnerships and any direct third-party costs will be paid by the party receiving the services. The shared costs will be 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.

 

As noted above, the cost sharing agreement reduces the costs to the Partnership for accounting and asset management services provided through a member of the General Partner. In addition to certain accounting and asset management resources, the Partnership and Energy 11 share the rent expense for leased office space (leased from an affiliate of a member of the general partner of Energy 11) in Oklahoma City, Oklahoma along with the compensation due to the President of Energy 11’s general partner. For the three and six months ended June 30, 2018, approximately $64,000 and $111,000, respectively, of expenses subject to the cost sharing agreement were incurred by the Partnership and will be reimbursed to Energy 11. At June 30, 2018, approximately $64,000 is due from the Partnership to Energy 11 and is included in Due to related parties in the consolidated balance sheets.

 

Note 8.  Subsequent Events

 

In July 2018, the Partnership closed on the issuance of approximately 0.4 million common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $8.4 million and proceeds net of selling and marketing costs of approximately $7.9 million.

 

In July 2018, the Partnership declared and paid $0.6 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

 

 

 

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, 2017 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 and acquisition activities in a timely manner and on terms that are consistent with what the Partnership projects;

•	uncertainties concerning the price of oil and natural gas, which may decrease and remain low for prolonged periods; and

•	the risk that any hedging policy the Partnership employs to reduce the effects of changes in the prices of the Partnership’s production will not be effective.

 

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

 

The following discussion and analysis should be read in conjunction with the Partnership’s Unaudited Consolidated Financial Statements and Notes thereto, appearing elsewhere in this Quarterly Report on Form 10-Q, as well as the information contained in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017.

 

Overview

 

Energy Resources 12, L.P. (the “Partnership”) was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership is offering common units of limited partner interest (the “common units”) on a best-efforts basis with the intention of raising up to $350,000,001 of capital, consisting of 17,631,579 common units. The Partnership’s Registration Statement on Form S-1 (File No. 333-216891) was declared effective by the Securities and Exchange Commission on May 17, 2017. As of July 25, 2017, the Partnership completed the sale of the minimum offering of common units for gross proceeds of approximately $25 million. Additionally upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990 and Energy Resources 12 GP, LLC (the “General Partner”) received Incentive Distribution Rights (defined below). As of June 30, 2018, the Partnership had completed the sale of 5.2 million common units for gross proceeds of approximately $100.5 million and proceeds net of offering costs of approximately $93.9 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 primarily oil and gas properties located onshore in the United States. The Partnership seeks to acquire working and other interests in producing and non-producing oil and natural gas properties in the United States and utilize third-party operators to manage the day-to-day operations of such properties.

 

Oil and Gas Properties Acquisition

 

On February 1, 2018, the Partnership completed its purchase of an approximate average 3.1% non-operated working interest in 204 producing wells and 30 wells in various stages of the drilling and completion process, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”) for $87.5 million. Prior to this acquisition, the Partnership owned no oil and natural gas assets. The Bakken Assets are operated by 14 third-party operators, including WPX Energy (NYSE: WPX), Marathon Oil (NYSE: MRO), EOG Resources (NYSE: EOG) and Continental Resources (NYSE: CLR). The Bakken Assets are located in the Bakken Shale formation, including the Antelope, Spotted Horn, Squaw Creek and Reunion Bay fields. The Bakken Shale and its close geologic cousin, the Three Forks Shale, are found in the Williston Basin, centered in North Dakota and are two of the largest oil fields in the U.S. While oil has been produced in North Dakota from the Williston Basin since the 1950s, it is only since 2007 through the application of horizontal drilling and hydraulic fracturing technologies that the Bakken has seen an increase in production activities.

 

The purchase price was funded by net proceeds from the Partnership’s ongoing public offering, proceeds from an unsecured term loan of $25.0 million (discussed in Liquidity and Capital Resources: Financing below) and an advance from a member of the General Partner of $7.0 million. The advance from a member of the General Partner was paid in full in May 2018. The advance did not bear interest and the member of the General Partner did not receive any compensation for the advance.

 

The purchase price for the Bakken Assets was $87.5 million, subject to customary post-closing adjustments. The Partnership adjusted the purchase price to reflect the operating revenues and expenses of the Bakken Assets between the acquisition effective date of September 1, 2017 and the closing date of February 1, 2018, in accordance with the closing conditions set forth in the purchase agreement. The net impact of the purchase price adjustments was a decrease to the purchase price of the asset of approximately $2.3 million.

 

From February 1, 2018 to June 30, 2018, the Partnership’s capital drilling costs incurred were approximately $2.9 million for the period for the Partnership’s participation in the drilling and completion of 55 wells, of which 36 have been completed as of June 30, 2018. The Partnership anticipates incurring an additional $0.7 million to complete the 19 wells in various stages of completion. The Partnership anticipates that it may be obligated to invest approximately $7 to $9 million in drilling and completion capital expenditures for the remainder of 2018 for additional planned drilling by its operators, and a total of approximately $55 to $60 million in drilling and completion capital expenditures through 2023 to fully participate in operator drilling programs in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements governing the Bakken Assets. Since the Partnership is not the operator of any of the Bakken Assets described, it is extremely difficult to predict the 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 for 2019 and beyond difficult to forecast and current estimated capital expenditure could be significantly different from amounts actually invested. The Partnership expects to fund capital additions related to the drilling and completion of wells primarily from cash provided by operating activities, proceeds from its best-efforts offering and cash on hand.

 

Potential Acquisition

 

On June 29, 2018, the Partnership, through a wholly-owned subsidiary (the “Buyer”) entered into a Purchase and Sale Agreement (“Purchase Agreement No. 2”) with Bruin E&P Non-Op Holdings, LLC (“Seller”), for the potential purchase of an additional portion of the Seller’s interest in the Bakken Assets, resulting in the Partnership acquiring an additional approximate average 2.7% non-operated working interest (the “Target Assets”), so if all conditions to closing on the Target Assets are met under the Purchase Agreement No. 2, the Partnership’s non-operated working interest in the Bakken Assets would increase to approximately 5.4%.

 

Pursuant to Purchase Agreement No. 2, the purchase price for the Target Assets is $82.5 million, subject to customary adjustments. On June 29, 2018, the Partnership funded a deposit of 5% of the purchase price, or $4,125,000 (the “Deposit”), to the Seller to be applied toward the purchase price at closing or to be released to the Seller if the transaction does not close by the outside closing date due to the Buyer’s breach of Purchase Agreement No. 2. In the event the transaction does not close due to a breach by Sellers, the Deposit will be refunded to the Partnership. If the Buyer does not perform under the contract as a result of its diligence review or otherwise breach Purchase Agreement No. 2, the Sellers’ sole remedy against the Buyer is release of the Deposit to the Seller. The final settlement purchase price is subject to the customary post-closing adjustments, as defined and identified in Purchase Agreement No. 2. 

 

 

The closing of Purchase Agreement No. 2 is subject to the satisfaction of a number of required conditions which currently remain unsatisfied under Purchase Agreement No. 2. Consummation of the acquisition is subject to the Buyer’s satisfactory completion of the review of title, environmental investigations, financial analysis and geological analysis, obtaining sufficient financing to fund the purchase price and other due diligence. Accordingly, there can be no assurance at this time that all of the conditions precedent to consummating Purchase Agreement No. 2 will be satisfied, that the Partnership will find the results of its diligence investigation acceptable, that the Partnership will be able to obtain sufficient financing on terms reasonably acceptable or that the transaction will be successfully completed.

 

The Partnership has engaged REI (see Note 3. Oil and Gas Investments for discussion of REI) to perform advisory and consulting services and support the Partnership through closing of Purchase Agreement No. 2, including assistance with due diligence related to the Target Assets and obtaining financing for the proposed transaction. The Partnership will pay REI a total of approximately $4.1 million for its advisory and consulting services. REI is also entitled to a fee of 5% of the gross sales price in the event the Partnership disposes any or all of the Target Assets, if surplus funds are available after Payout to the holders of the Partnership’s common units, as defined below.

 

Current Price Environment

 

Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control. Due to global supply and demand concerns as well as ongoing geopolitical risks in oil producing regions of the world, energy commodity prices are historically volatile and may continue into the future. The average daily NYMEX prices for oil and natural gas for the three months ended June 30, 2018 were $67.91 per barrel of oil and $2.85 per Mcf of natural gas, respectively. The average daily NYMEX prices for oil and natural gas from February 1, 2018 to June 30, 2018 were $65.83 per barrel of oil and $2.79 per Mcf of natural gas, respectively.

 

Results of Operations

 

The Partnership closed on its purchase of the Bakken Assets on February 1, 2018. Other than the payment of fees and expenses described herein, the Partnership had no other operations prior to the acquisition of the Bakken Assets. Because the Partnership had no revenues in fiscal 2017, there is no comparison of the Partnership’s results of operations for the three and six months ended June 30, 2018 to the Partnership’s results of operations for the three and six months ended June 30, 2017, except as otherwise indicated below.

 

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 and (3) production costs per BOE. The following table is a summary of the results from operations, including production, of the Partnership’s non-operated working interest in the Bakken Assets for the three months ended June 30, 2018 and the five-month period February 1, 2018 to June 30, 2018.

 

		Three Months Ended June 30,								Five Months Ended June 30,
		2018				Percent of Revenue				2018				Percent of Revenue
Total revenue		$	7,531,096				100.0	%		$	11,028,175				100.0	%
Production expenses			1,635,724				21.7	%			2,268,627				20.6	%
Production taxes			617,248				8.2	%			938,526				8.5	%
Depreciation, depletion, amortization and accretion			1,321,361				17.5	%			2,016,079				18.3	%
Production (BOE):
Oil			106,316								162,820
Natural gas			18,454								23,404
Natural gas liquids			14,009								21,137
Total			138,779								207,361
Average sales price per unit:
Oil (per Bbl)		$	66.02							$	62.69
Natural gas (per Mcf)			2.64								2.67
Natural gas liquids (per Bbl)			15.71								21.03
Combined average sales price (per BOE)			54.27								53.18
Average unit cost per BOE:
Production expenses			11.79								10.94
Production taxes			4.45								4.53
Depreciation, depletion, amortization and accretion			9.52								9.72

 

 

Oil, Natural Gas and NGL Sales

 

For the three months ended June 30, 2018, revenues for oil, natural gas and NGL sales were $7.5 million. Revenues for the sale of crude oil were $7.0 million, which resulted in a realized price of $66.02 per barrel. Revenues for the sale of natural gas were $0.3 million, which resulted in a realized price of $2.64 per Mcf. Revenues for the sale of NGLs were $0.2 million, which resulted in a realized price of $15.71 per BOE of production.

 

For the five months from February 1, 2018 to June 30, 2018, revenues for oil, natural gas and NGL sales were $11.0 million. Revenues for the sale of crude oil were $10.2 million, which resulted in a realized price of $62.69 per barrel. Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $2.67 per Mcf. Revenues for the sale of NGLs were $0.4 million, which resulted in a realized price of $21.03 per BOE of production.

 

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 contracts in effect for the extraction, transportation and treatment of natural gas.

 

Production expenses for the three months ended June 30, 2018 were $1.6 million, and production expenses per BOE were $11.79. Production expenses for the five months from February 1, 2018 to June 30, 2018 were $2.3 million, and production expenses per BOE were $10.94.

 

Production Taxes

 

Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. Taxes on the sale of gas and NGL products are less than taxes levied on the sale of oil. Production taxes for the three months ended June 30, 2018 were $0.6 million (8.2% of revenue). Production taxes for the five months from February 1, 2018 to June 30, 2018 were $0.9 million (8.5% of revenue).

 

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. The Partnership’s DD&A for the three months ended was $1.3 million, and DD&A per BOE of production was $9.52. DD&A for the five months from February 1, 2018 to June 30, 2018 was $2.0 million, and DD&A per BOE of production was $9.72.

 

General and Administrative Costs

 

The principal components of general and administrative expense are accounting, legal, advisory and consulting fees. General and administrative costs for the three months ended June 30, 2018 and 2017 were $0.3 million and $14,845, respectively. General and administrative expenses for the six months ended June 30, 2018 and 2017 were $0.7 million and $21,105, respectively. General and administrative expenses for the three and six months ended June 30, 2018 exceeded those of the prior year due to the Partnership raising funds through its ongoing offering and closing on its non-operated working interest in the Bakken Assets in February 2018, resulting in a rise in year-to-date accounting, legal and consulting fees.

 

Interest Expense

 

Interest expense, net, for the three months ended June 30, 2018 and 2017 was $0.2 million and $830, respectively. Interest expense, net, for the six months ended June 30, 2018 and 2017 was $0.4 million and $1,105, respectively. The primary component of Interest expense, net, during the three and six months ended June 30, 2018 was interest expense on the Term Loan, as discussed below in Liquidity and Capital Resources: Financing.

 

 

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 Partnership’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 operators.

 

The following table reconciles the Partnership’s GAAP net income to EBITDAX for the three and six months ended June 30, 2018.

 

		Three Months Ended June 30, 2018				Six Months Ended June 30, 2018
Net income		$	3,400,535			$	4,688,860
Interest expense, net			212,483				372,049
Depreciation, depletion, amortization and accretion			1,321,361				2,016,079
Exploration expenses			-				-
EBITDAX		$	4,934,379			$	7,076,988

 

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

 

Liquidity and Capital Resources

 

The Partnership’s principal source of liquidity will be the proceeds of the best-efforts offering and the cash flow generated from properties the Partnership acquired on February 1, 2018. The Partnership anticipates that cash on hand, cash flow from operations, additional financing and proceeds of the best-efforts offering will be adequate to meet its liquidity requirements for at least the next 12 months. If the Partnership is unable to raise sufficient proceeds from its ongoing best-efforts offering or obtain additional financing, it may be unable to complete the potential acquisition of additional non-operated working interests in the Bakken Assets discussed above, pay distributions or participate in the drilling programs discussed above.

 

Financing

 

On January 16, 2018, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”) with Bank of America, N.A. (the “Lender”), which provides for an unsecured term loan (the “Term Loan”) of $25 million. The Term Loan bears interest at a variable rate based on the London Inter-Bank Offered Rate (LIBOR) plus a margin of 2.00%. Interest is payable monthly. The maturity date is January 15, 2019.

 

The Term Loan proceeds were used in closing on the Partnership’s purchase of the Bakken Assets, as described above. Under the terms of the Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. Glade M. Knight and David S. McKenney, the General Partner’s Chief Executive Officer and Chief Financial Officer, respectively, have guaranteed repayment of the Term Loan and did not and will not receive any consideration in exchange for providing this guarantee. The Partnership intends to use proceeds from its best-efforts offering to repay the Term Loan. At June 30, 2018, the outstanding balance on the Term Loan was $15.0 million.

 

 

Partners’ Equity

 

The Partnership intends to continue to raise capital through its best-efforts offering of common units by the Managing Dealer at $20.00. Under the agreement with the Managing Dealer, the Managing Dealer receives a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through June 30, 2018, the Dealer Manager Incentive Fees are approximately $4.0 million, subject to Payout (defined below). As of June 30, 2018, the Partnership had completed the sale of 5.2 million common units for gross proceeds of approximately $100.5 million and proceeds net of offering costs of approximately $93.9 million.

 

Distributions

 

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 and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.

 

The Partnership Agreement provides that “Payout”, which is defined below, 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 common unit, regardless of the amount paid for the common 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, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

 

●	Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

 

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

 

For the three and six months ended June 30, 2018, the Partnership paid distributions of $0.349041 and $0.698082 per common unit, or $1.4 million and $2.6 million, respectively.

 

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 intended rate of distribution will be based on its ability to increase its cash generated from operations. As there can be no assurance that the assets acquired by the Partnership 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.

 

Subsequent Events

 

In July 2018, the Partnership closed on the issuance of approximately 0.4 million common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $8.4 million and proceeds net of selling and marketing costs of approximately $7.9 million.

 

In July 2018, the Partnership declared and paid $0.6 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

 

 

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 June 30, 2018 to provide reasonable assurance that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Partnership’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.

 

Change in Internal Controls Over Financial Reporting

 

There have not been any changes in the Partnership’s internal controls over financial reporting that occurred during the quarterly period ended June 30, 2018 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 Partnership’s 2017 Annual Report on Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2017 Form 10-K. 

 

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

 

The Partnership’s Registration Statement on Form S-1 (File No. 333-216891) was declared effective by the Securities and Exchange Commission on May 17, 2017. Under the public offering the Partnership made under the Registration Statement (as supplemented), the Partnership is offering common units of limited partner interest (the “common units”) on a best-efforts basis with the intention of raising up to $350,000,001 of capital, consisting of 17,631,579 common units. As of June 30, 2018, the Partnership had completed the sale of 5,157,398 common units for total gross proceeds of $100.5 million and proceeds net of offering costs including selling commissions and marketing expenses of $93.9 million. As of June 30, 2018, 12,474,181 common units remained unsold. The offering will expire on May 17, 2019, unless extended by the General Partner, provided that the offering will be terminated if all of the common units are sold before then. The public offering is being made through David Lerner Associates, Inc. (the “Managing Dealer”). In October 2017, the Partnership completed the sale of 2,631,579 common units at $19.00 per common unit, or $50 million. All subsequent common units are being sold at $20.00 per common unit.

 

Under the Partnership’s agreement with the Managing Dealer, the Managing Dealer receives a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees, 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 June 30, 2018, the Dealer Manager Incentive Fees are up to approximately $4.0 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 table sets forth information concerning the on-going best-efforts offering and the use of proceeds from the offering as of June 30, 2018.

 

Units Registered
				2,631,579		Units		$	19.00		per unit		$	50,000,001
				15,000,000		Units		$	20.00		per unit			300,000,000
Totals:				17,631,579		Units							$	350,000,001
Units Sold
				2,631,579		Units		$	19.00		per unit		$	50,000,001
				2,525,819		Units		$	20.00		per unit			50,516,379
Totals:				5,157,398		Units							$	100,516,380
Expenses of Issuance and Distribution of Units
	1.		Underwriting commissions										$	6,030,983
	2.		Expenses of underwriters											-
	3.		Direct or indirect payments to directors or officers of the Partnership or their associates, or to affiliates of the Partnership											-
	4.		Fees and expenses of third parties											558,358
	Total Expenses of Issuance and Distribution of Common Shares													6,589,341
Net Proceeds to the Partnership													$	93,927,039
	1.		Purchase of oil, gas and natural gas liquids properties (net of debt, proceeds and repayment including interest and acquisition costs)										$	77,940,811
	2.		Deposits and other costs associated with potential oil, natural gas and natural gas liquids acquisitions											4,125,000
	3.		Repayment of other indebtedness, including interest expense paid											-
	4.		Investment and working capital											7,771,006
	5.		Fees and expenses of third parties											-
	6.		Other											-
	7.		Distributions											4,090,222
Total Application of Net Proceeds to the Partnership													$	93,927,039

 

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
2.1		Purchase and Sale Agreement dated June 29, 2018 by and between Energy Resources 12 Operating Company, LLC, as Purchaser, and Bruin E&P Non-Op Holdings, LLC, as Seller (incorporated by reference from Exhibit 2.1 to the Partnership’s Current Report on Form 8-K filed on July 6, 2018).
10.1		Loan Agreement between Bank of America, N.A. and Energy Resources 12, L.P. dated January 16, 2018 (incorporated by reference from Exhibit 10.1 to the Partnership’s form 8-K filed on January 17, 2018).
10.2		Cost Sharing Agreement between Energy Resources 12, L.P., Energy 11, L.P. and Energy 11 Management, LLC, dated January 31, 2018 (incorporated by reference from Exhibit 10.7 to Post-Effective Amendment No. 1 to the Partnership’s Registration Statement on Form S-1 filed on February 1, 2018).
10.3		Advisory and Administration Agreement dated June 29, 2018 by and between Energy Resources 12 Operating Company, LLC, Energy Resources 12, L.P., and Regional Energy Investors, LP (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on July 6, 2018).
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 Resources 12, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 formatted in XBRL (eXtensible Business Reporting Language): (i) the Balance Sheets, (ii) the Statements of Operations, (iii) the Statement of Cash Flows, and (iv) related notes to these financial statements, tagged as blocks of text and in detail*

 

*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 Resources 12, L.P.
By: Energy Resources 12 G.P., LLC, its General Partner
By:	/s/ Glade M. Knight
	Glade M. Knight
	Chief Executive Officer (Principal Executive Officer)
By:	/s/ David S. McKenney
	David S. McKenney
	Chief Financial Officer (Principal Financial and Accounting Officer)
Date: August 14, 2018