UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

FORM 10-Q 

For the quarterly period ended March 31, 2019

Commission File Number 000-55916

Energy Resources 12, L.P.

(Exact name of registrant as specified in its charter)

(817) 882-9192

(Registrant’s telephone number, including area code)

 Securities registered pursuant to Section 12(b) of the Act:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☑  No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑   No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☑

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐   No ☑

As of April 30, 2019, the Partnership had 8,940,509 common units outstanding.  

Energy Resources 12, L.P.

Form 10-Q

Index

PART I. FINANCIAL INFORMATION

Item 1.  Financial Statements

Energy Resources 12, L.P.

Consolidated Balance Sheets

See notes to consolidated financial statements.

Energy Resources 12, L.P.

Consolidated Statements of Operations

(Unaudited)

See notes to consolidated financial statements.

See notes to consolidated financial statements.

Energy Resources 12, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

See notes to consolidated financial statements.

Energy Resources 12, L.P.

Notes to Consolidated Financial Statements

March 31, 2019

(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 offering was extended in February 2019 and in accordance with the prospectus, the offering will expire on November 18, 2019 or the sale of all common units, whichever occurs first.

As of March 31, 2019, the Partnership owned an approximate 6.0% non-operated working interest in 277 currently producing wells, 33 wells in various stages of the drilling and completion process and additional future development locations, 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, 2018 financial statements included in its 2018 Annual Report on Form 10-K. Operating results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2019. 

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 March 31, 2019, the Partnership had completed the sale of 8.7 million common units for gross proceeds of approximately $170.9 million and proceeds net of offering costs of approximately $160.0 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 Per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three months ended March 31, 2019 and 2018. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.

Recently Adopted Accounting Standards

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

Note 3.  Oil and Gas Investments

On February 1, 2018, the Partnership completed its purchase (“Acquisition No. 1”) in the Bakken Assets for approximately $87.5 million, and customary adjustments and capitalized transaction costs of approximately $2.9 million. Acquisition No. 1 was funded using proceeds from the Partnership’s best-efforts offering, proceeds from an unsecured term loan of $25.0 million and an advance from a member of the General Partner of $7.0 million. The term loan (discussed below in Note 5. Debt) was repaid in full and extinguished in December 2018. The advance from a member of the General Partner was repaid 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 Partnership also recorded an asset retirement obligation liability of approximately $0.1 million in conjunction with this acquisition.

On August 31, 2018, the Partnership completed its purchase (“Acquisition No. 2”) of an additional non-operated working interest in the Bakken Assets for approximately $82.5 million, subject to customary adjustments, and was funded using proceeds from the Partnership’s best-efforts offering and proceeds from a line of credit of $60.0 million (discussed below in Note 5. Debt). The Partnership accounted for Acquisition No. 2 as a purchase of a group of similar assets, and therefore capitalized transaction costs associated with this acquisition. The capitalized acquisition-related costs, which included but were not limited to fees for advisory and consulting (discussed below), due diligence, legal, accounting, engineering and environmental review services, for Acquisition No. 2 totaled approximately $2.9 million. The Partnership also recorded an asset retirement obligation liability of approximately $0.2 million in conjunction with this acquisition.

The Partnership adjusted the purchase price of Acquisition No. 2 to reflect the Partnership’s estimate of the customary settlement of operating revenues and expenses received or paid by the seller on the Partnership’s behalf between the effective date of March 1, 2018 and the closing date of August 31, 2018. The estimate, which is preliminary and was derived from operator revenue and expense statements received from the seller, reduced the purchase price of the Bakken Assets by approximately $4.3 million. In accordance with the terms of the purchase agreement, the Partnership and the seller will agree to the final settlement of operating revenues and expenses between the effective and closing dates of the acquisition after all operator information has been received, and the Partnership will adjust its estimate at that time.

In November 2017, the Partnership engaged Regional Energy Investors, LP (“REI”) to perform advisory and consulting services, including supporting the Partnership through closing and post-closing of Acquisition No. 1. In the first quarter of 2018, the Partnership paid REI a total of approximately $5.3 million for its advisory and consulting services related to Acquisition No. 1. Of the $5.3 million paid to REI, approximately $4.7 million of these services related to Acquisition No. 1 were capitalized as part of the acquisition costs described above. In June 2018, the Partnership re-engaged REI to perform advisory and consulting services and support the Partnership through closing and post-closing of Acquisition No. 2, including assistance with due diligence and obtaining financing for Acquisition No. 2. In the third quarter of 2018, the Partnership paid REI a total of $4.1 million for its advisory and consulting services related to Acquisition No. 2. Of the $4.1 million, approximately $2.7 million of these services related to Acquisition No. 2 were capitalized as part of the acquisition costs described above. The remaining $1.4 million was capitalized as deferred loan costs and are being amortized over the life of the revolving credit facility described in Note 5. Debt. The deferred loan costs are recorded as Other assets, net on the Partnership’s consolidated balance sheet..

Under the advisory and administration agreements (the “Agreements”) with REI, REI was also entitled to a fee of 5% of the gross sales price in the event the Partnership disposed of 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 8. Capital Contribution and Partners’ Equity below. On December 28, 2018, the Partnership terminated the Agreements with REI, which extinguished any potential fee upon sale of certain of the Partnership’s assets as was required under the Agreements. At the time of the extinguishment, the payment of a fee was not probable and there was no value to the rights owned by REI. In connection with the termination, the General Partner issued 500 of its Class B Units to each of Pope Energy Investors, LP and CFK Energy, LLC. The General Partner received $250 from each of Pope Energy Investors, LP and CFK Energy, LLC for this transaction. The General Partner Class B Units are non-voting and participate in 50% of any distributions by the General Partner from proceeds of its Incentive Distribution Rights, after Payout and the Dealer Manager Incentive Fees, as described in Note 8. Capital Contribution and Partners’ Equity below.

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. In addition, CFK Energy, LLC and Pope Energy Investors, LP are owned by entities controlled by Messrs. Keating and Mallick, respectively. See Note 9. Related Parties below for additional information.

The following unaudited pro forma financial information for the three months ended March 31, 2018 have been prepared as if Acquisitions No. 1 and No. 2 of the Bakken Assets had occurred on January 1, 2018. 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.

As of March 31, 2019, the Partnership’s ownership of the Bakken Assets consisted of an approximate 6.0% non-operated working interest in 277 currently producing wells and 33 wells in various stages of the drilling and completion process.

From September 1, 2017, the effective date of Acquisition No. 1, to March 31, 2019, the Partnership has participated in the drilling of 109 wells, of which 76 have been completed and the other 33 wells are in various stages of completion at March 31, 2019. For the three months ended March 31, 2019 and 2018, the Partnership incurred approximately $11.2 million and $0.4 million, respectively, in capital drilling and completion costs. As of March 31, 2019 and 2018, the Partnership had approximately $11.2 million and $0.4 million in outstanding capital expenditures, which are included in Accounts payable and accrued liabilities on the Partnership’s consolidated balance sheet. The Partnership anticipates approximately $8 to $10 million of capital expenditures will be incurred during the remainder of 2019 to complete the 33 wells in various stages of completion at March 31, 2019.

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:

Note 5.  Debt

On January 16, 2018, the Partnership entered into a loan agreement with Bank of America, N.A. (“BOA”), which provides for an unsecured term loan (the “Term Loan”) of $25 million. The Term Loan was paid in full and extinguished in December 2018. Interest was payable monthly, and the Term Loan bore interest at a variable rate based on the London Inter-Bank Offered Rate (LIBOR) plus a margin of 2.00%. The Term Loan proceeds were used in closing on Acquisition No. 1, as described above. Glade M. Knight and David S. McKenney, the General Partner’s Chief Executive Officer and Chief Financial Officer, respectively, had guaranteed repayment of the Term Loan and did not receive any consideration in exchange for providing this guarantee.

On August 31, 2018, the Partnership entered into a loan agreement (“Loan Agreement”) with Simmons Bank as administrative agent and the lenders party thereto (collectively, the “Lender”), which provides for a revolving credit facility (the “Credit Facility”) with an initial commitment amount of $60 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The commitment amount may be increased up to $100 million with Lender approval. At closing, the Partnership paid an origination fee of 0.50% of the Revolver Commitment Amount, or $300,000, and is subject to additional origination fees of 0.50% for any increase to the commitment made in excess of the Revolver Commitment Amount. The Partnership is also required to pay an unused facility fee at an annual rate of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter. The maturity date is August 31, 2021 (“Maturity Date”).

The interest rate, subject to certain exceptions, is equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.75% to 3.75%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Loan Agreement. At March 31, 2019, the Lender commitment was $40.0 million and the interest rate for the Credit Facility was approximately 5.95%. At March 31, 2019, the outstanding balance on the Credit Facility was approximately $30.0 million. Outstanding borrowings under the Credit Facility cannot exceed the lesser of the borrowing base or the Revolver Commitment Amount at any time.

At closing, the Partnership borrowed $60.0 million. The proceeds were used to fund the purchase of Acquisition No. 2 described above and to pay closing costs. Subject to availability, the Credit Facility may also provide additional liquidity for future capital investments, including the drilling and completion of proposed wells by the operators of the Partnership’s properties, and other corporate working capital requirements. Under the terms of the Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells. 

The Credit Facility contains mandatory prepayment requirements (including those described above), customary affirmative and negative covenants and events of default. The financial covenants as defined in the Loan Agreement include:

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

The outstanding balances of the Credit Facility of approximately $30.0 million and $39.5 million at March 31, 2019 and December 31, 2018, respectively, approximate the fair market value of the Credit Facility. The Partnership estimated the fair values of the Credit Facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

Note 6. Fair Value of Financial Instruments

The Partnership follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows:

The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the three months ended March 31, 2019 and 2018, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2019 and December 31, 2018.

The Level 2 instruments presented in the table above consist of the Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheets as Derivative liability at March 31, 2019 and Derivative asset at December 31, 2018. See additional detail in Note 7. Risk Management.

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s cash and cash equivalents, oil, natural gas and natural gas liquids revenue receivable, accounts payable and accrued expenses reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments. In addition, see Note 5. Debt for the fair value discussion on the Partnership’s debt.

Note 7. Risk Management

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Under the Credit Facility, the Partnership is required to maintain a risk management program, covering at least 50% of the Partnership’s total estimated monthly production of oil and natural gas through the maturity date of August 31, 2021. Therefore, in December 2018 and March 2019, the Partnership entered into derivative contracts, with two different counterparties, through September 2020 to manage the commodity price risk on a portion of the Partnership’s anticipated future oil and gas production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations.

All derivative instruments are recorded on the Partnership’s balance sheet as assets or liabilities measured at fair value. As of March 31, 2019, the Partnership’s derivative instruments were in a net loss position; therefore, a liability of approximately $1.0 million, which approximates its fair value, has been recognized as a Derivative liability (current and noncurrent) on the Partnership’s consolidated balance sheet as of March 31, 2019. As of December 31, 2018, the Partnership’s derivative instruments were in a net gain position; therefore, an asset of approximately $0.9 million, which approximates its fair value, was recognized as a Derivative asset (current and noncurrent) on the Partnership’s consolidated balance sheet as of December 31, 2018.

The Partnership determines the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performs an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional discussion above in Note 6. Fair Value of Financial Instruments.

The Partnership has not designated its derivative instruments as hedges for accounting purposes and has not entered into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value, in addition to gains or losses on settlements, are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The Partnership recognized a mark-to-market loss of approximately $1.9 million for the three months ended March 31, 2019, which was recorded on the consolidated statements of operations as Loss on derivatives.

The following table presents settlements on matured derivative instruments and non-cash losses on open derivative instruments for the periods presented. The Partnership’s derivative contracts that expired during the first quarter of 2019 were settled at no cost or benefit to the Partnership, as the contract price on the date of settlement was within the established floor and ceiling prices. Non-cash losses below represent the change in fair value of derivative instruments which were held at period-end.

The Partnership’s derivative contracts are costless collars, which are used to establish floor and ceiling prices on future anticipated oil and gas production and are settled monthly. While the use of these derivative instruments limits the downside risk of adverse price movement, they may also limit future revenues from favorable price movement. The Partnership did not pay or receive a premium related to the costless collar agreements. The following table reflects the open costless collar instruments as of March 31, 2019.

The use of derivative instruments involves the risk that the Partnership’s counterparties will be unable to meet the financial terms of such instruments. The Partnership has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments, which allow these assets and liabilities to be netted on the Partnership’s consolidated balance sheet. 

The Partnership’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDA”) entered into with the counterparties. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately.

Note 8.  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. The offering will end on the earlier of all common units registered being sold, or November 18, 2019. As of March 31, 2019, the Partnership had completed the sale of 8.7 million common units for gross proceeds of approximately $170.9 million and proceeds net of offering costs of approximately $160.0 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 March 31, 2019, the Dealer Manager Incentive Fees are approximately $6.8 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:

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 months ended March 31, 2019 and 2018, the Partnership paid distributions of $0.349041 per common unit in both periods, or $2.8 million and $1.2 million, respectively.

Note 9.  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 March 31, 2019, the management fee for the three months ended March 31, 2019 due to the General Partner is approximately $214,000, which has been accrued on the consolidated balance sheets in Due to related parties at March 31, 2019 and included in General and administrative expenses on the consolidated statements of operations. The management fee paid to the General Partner for the three months ended March 31, 2018 was $59,000.

The Partnership also will reimburse the General Partner for certain general and administrative costs. For the three months ended March 31, 2019 and 2018, approximately $95,000 and $81,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At March 31, 2019, approximately $95,000 was due to a member of the General Partner and is included in Due to related parties in the consolidated balance sheets.

The Chief Executive Officer and Chief Financial Officer of the Partnership’s General Partner are also partners and 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. Two additional partners of the general partner of Energy 11 are holders of the Class B Units of the Partnership’s General Partner. On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11 that gives 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 are split evenly between the two partnerships and any direct third-party costs are paid by the party receiving the services. The shared costs are based on actual costs incurred with no mark-up or profit to the Partnership. The agreement may be terminated at any time by either party upon 60 days written notice.

The 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 months ended March 31, 2019 and 2018, approximately $65,000 and $47,000, respectively, of expenses subject to the cost sharing agreement were incurred by the Partnership and have been or will be reimbursed to Energy 11. At March 31, 2019, approximately $65,000 is due from the Partnership to Energy 11 and is included in Due to related parties in the consolidated balance sheets.

Note 10.  Subsequent Events

In April 2019, the Partnership declared and paid $0.9 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

In April 2019, the Partnership closed on the issuance of approximately 0.3 million common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $5.3 million and proceeds net of selling and marketing costs of approximately $4.9 million.

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” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018 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, 2018.

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 March 31, 2019, the Partnership had completed the sale of 8.7 million common units for gross proceeds of approximately $170.9 million and proceeds net of offering costs of approximately $160.0 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. On February 1, 2018, the Partnership completed its first purchase (“Acquisition No. 1”) in the Williston Basin of North Dakota, acquiring, at closing, non-operated working interests in producing wells and in-process wells, along with additional future development locations, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”), for approximately $87.5 million, subject to customary adjustments. On August 31, 2018, the Partnership closed on its second asset purchase (“Acquisition No. 2”), acquiring an additional non-operated working interest in the Bakken Assets for approximately $82.5 million, subject to customary adjustments. Prior to these acquisitions, the Partnership owned no oil and natural gas assets. The Partnership utilized proceeds from its ongoing best-efforts offering and available financing to close on the acquisitions. See further discussion below under Liquidity and Capital Resources.

As a result of these acquisitions and completed drilling during the period of ownership, as of March 31, 2019, the Partnership had an approximate 6.0% non-operated working interest in the Bakken Assets, consisting of 277 producing wells, 33 wells in various stages of the drilling and completion process and additional future development locations. 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 Bakken Assets are operated by 14 third-party operators, including WPX Energy (NYSE: WPX), Marathon Oil (NYSE: MRO), EOG Resources (NYSE: EOG), Continental Resources (NYSE: CLR) and RimRock Oil and Gas.

Current Price Environment

The oil and natural gas industry is affected by many factors that the Partnership generally cannot control, including the prices of oil, natural gas and natural gas liquids (“NGL”). Historically, world-wide oil and natural gas prices and markets have been subject to significant change and may continue to be in the future. The monthly average of $70.98 per barrel of oil in July 2018 represented the highest monthly average since November 2014. However, as a result of several of the factors discussed below, oil prices declined in November and December 2018, with December’s monthly average of $48.97 per barrel of oil being the lowest monthly average per barrel of oil since August 2017. In 2019, oil prices have increased from the December 2018 lows; the average price for oil for the three months ended March 31, 2019 was $54.74 per barrel.

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

Factors contributing to world-wide commodity pricing volatility include real or perceived geopolitical risks in oil-producing regions of the world, particularly the Middle East; forecasted levels of global economic growth combined with forecasted global supply; supply levels of oil and natural gas due to exploration and development activities in the United States; actions taken by the Organization of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. In addition to commodity price fluctuations, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.

The following table lists average NYMEX prices for oil and natural gas for the periods defined below.

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. Since September 1, 2017, the effective date of Acquisition No. 1, the Partnership has participated in the drilling of 109 wells.

Results of Operations

The Partnership closed on its first and second purchases of the Bakken Assets on February 1, 2018 and August 31, 2018, respectively. As a result, the comparability of results for the three months ended March 31, 2019 and 2018 as discussed below is impacted by these transactions. Other than the payment of fees and expenses described herein, the Partnership had no other operations prior to the acquisition of the Bakken Assets.

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 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 March 31, 2019 and 2018.

Oil, Natural Gas and NGL Revenues

For the three months ended March 31, 2019, revenues for oil, natural gas and NGL sales were $11.4 million. Revenues for the sale of crude oil were $10.7 million, which resulted in a realized price of $52.51 per barrel. Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $3.43 per Mcf. Revenues for the sale of NGLs were $0.3 million, which resulted in a realized price of $15.22 per BOE of production. For the two months from February 1, 2018 to March 31, 2018, revenues for oil, natural gas and NGL sales were $3.5 million. Revenues for the sale of crude oil were $3.2 million, which resulted in a realized price of $56.45 per barrel. Revenues for the sale of natural gas were $0.1 million, which resulted in a realized price of $2.80 per Mcf. Revenues for the sale of NGLs were $0.2 million, which resulted in a realized price of $31.50 per BOE of production.

The Partnership’s sold production for the Bakken Assets was approximately 2,700 BOE per day for the three months ended March 31, 2019. Production volumes per day will fluctuate due to the timing of well completions. Since the Partnership’s first acquisition in February 2018, approximately 49 new wells have been completed. New wells often have high levels of production immediately following completion, then decline to more consistent levels. If the Partnership had completed Acquisitions No. 1 and No. 2 on January 1, 2018, the Partnership estimates production for the Bakken Assets would have been approximately 2,400 BOE per day for the three months ended March 31, 2018.

Production is dependent on the investment in existing wells and the development of new wells. As noted above, the Partnership will experience natural production declines in the months following the completion of new wells. As further discussed in Liquidity and Capital Resources: Oil and Natural Gas Properties below, the Partnership has 33 wells currently in various stages of drilling and completion and therefore, expects production volume to increase in conjunction with the completion of those wells. However, if the Partnership or its operators are unable or it is not cost beneficial to continue 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, 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 March 31, 2019 were $2.6 million, and production expenses per BOE were $10.89. Production expenses for the two months from February 1, 2018 to March 31, 2018 were $0.6 million, and production expenses per BOE were $9.23.

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 March 31, 2019 were $1.0 million (8.9% of revenue). Production taxes for the two months from February 1, 2018 to March 31, 2018 were $0.3 million (9.2% 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 March 31, 2019 was $2.8 million, and DD&A per BOE of production was $11.51. The Partnership’s DD&A for the two months from February 1, 2018 to March 31, 2018 was $0.7 million, and DD&A per BOE of production was $10.13.

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 March 31, 2019 and 2018 were $0.8 million and $0.4 million, respectively. General and administrative expenses for the three months ended March 31, 2019 exceeded those of the prior year quarter due to the Partnership raising funds through its ongoing offering and the acquisitions of non-operated working interest in the Bakken Assets in February and August 2018, resulting in an increase in quarter-to-date accounting, consulting and advisory fees.

Interest Expense, net

Interest expense, net for the three months ended March 31, 2019 and 2018 was $0.7 million and $0.2 million, respectively. The primary component of Interest expense, net, during the three months ended March 31, 2019 was interest expense on the Credit Facility, while the primary component of Interest expense, net, during the three months ended March 31, 2018 was interest expense on the Term Loan, as discussed below in Liquidity and Capital Resources: Financing.

Loss on Derivatives

Under the Credit Facility, the Partnership is required to maintain a risk management program that covers at least 50% of the Partnership’s total estimated monthly production of oil and natural gas through the Credit Facility maturity date of August 31, 2021. In December 2018 and March 2019, the Partnership entered into derivative contracts with the objective to manage the commodity price risk on future oil and natural gas production. As of March 31, 2019, the Partnership’s derivative contracts (costless collar) were in a net loss position based upon the contracts’ estimated fair market value at the balance sheet date. Based upon the estimated fair value of the derivative contracts as of March 31, 2019, the Partnership recorded a mark-to-market loss of approximately $1.9 million for the three months ended March 31, 2019. Changes in the fair value of the unsettled derivative contracts represent mark-to-market gains and losses and are recorded on the Partnership’s consolidated statements of operations. The mark-to-market loss recorded by the Partnership does not represent an actual settlement and no payment was made to the Partnership’s counterparties during the first quarter of 2019. The Partnership’s derivative contracts that expired during the first quarter of 2019 were settled at no cost or benefit to the Partnership, as the contract price on the date of settlement was within the established floor and ceiling prices.

The table below summarizes the Partnership’s outstanding derivative contracts (costless collars – purchased put options and written call options) on the Partnership’s future oil and natural gas production.

Supplemental Non-GAAP Measure

The Partnership uses “Adjusted EBITDAX”, defined as Earnings before (i) interest expense, net; (ii) income taxes; (iii) depreciation, depletion, amortization and accretion; (iv) exploration expenses; and (v) (gain)/loss on the mark-to-market of derivative instruments, as a key supplemental measure of its operating performance. This non-GAAP financial measure should be considered along with, but not as an alternative to, net income, operating income, cash flow from operating activities or other measures of financial performance presented in accordance with GAAP. Adjusted EBITDAX is not necessarily indicative of funds available to fund the Partnership’s cash needs, including its ability to make cash distributions. Although Adjusted EBITDAX, as calculated by the Partnership, may not be comparable to Adjusted EBITDAX as reported by other companies that do not define such 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 Adjusted EBITDAX is important to provide investors with additional information (i) to provide an important supplemental indicator of the operational performance of the Partnership’s business without regard to financing methods and capital structure, and (ii) to measure the operational performance of the Partnership’s operators.

The following table reconciles the Partnership’s GAAP net income to Adjusted EBITDAX for the three months ended March 31, 2019 and 2018.

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 9. 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, the cash flow generated from properties the Partnership has acquired and availability, if any, under the Partnership’s revolving credit facility discussed below. The Partnership anticipates that cash on hand, cash flow from operations, availability under the revolving credit facility and proceeds of the best-efforts offering will be adequate to meet its liquidity requirements for at least the next 12 months, including completing capital expenditures discussed below. If the Partnership is unable to raise sufficient proceeds from its ongoing best-efforts offering or obtain additional financing, it may default on its financial covenants under the revolving credit facility and be unable to pay distributions or participate in the drilling programs as proposed by the operators of the Bakken Assets.

Financing

On January 16, 2018, the Partnership entered into a loan agreement with Bank of America, N.A. (“BOA”), which provided for an unsecured term loan (the “Term Loan”) of $25 million. The Term Loan was paid in full and extinguished in December 2018. Interest was payable monthly, and the Term Loan bore interest at a variable rate based on the London Inter-Bank Offered Rate (LIBOR) plus a margin of 2.00%. The Term Loan proceeds were used in closing on Acquisition No. 1, as described above. Glade M. Knight and David S. McKenney, the General Partner’s Chief Executive Officer and Chief Financial Officer, respectively, had guaranteed repayment of the Term Loan and did not receive any consideration in exchange for providing this guarantee.

On August 31, 2018, the Partnership entered into a loan agreement (“Loan Agreement”) with Simmons Bank as administrative agent and the lenders party thereto (collectively, the “Lender”), which provides for a revolving credit facility (the “Credit Facility”) with an initial commitment amount of $60 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The commitment amount may be increased up to $100 million with Lender approval. At closing, the Partnership paid an origination fee of 0.50% of the Revolver Commitment Amount, or $300,000, and is subject to additional origination fees of 0.50% for any increase to the commitment made in excess of the Revolver Commitment Amount. The Partnership is also required to pay an unused facility fee at an annual rate of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter. The maturity date is August 31, 2021 (“Maturity Date”).

The interest rate, subject to certain exceptions, is equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.75% to 3.75%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Loan Agreement. At March 31, 2019, the Lender commitment was $40.0 million and the interest rate for the Credit Facility was approximately 5.95%. As of March 31, 2019, the outstanding balance on the Credit Facility was approximately $30.0 million. Outstanding borrowings under the Credit Facility cannot exceed the lesser of the borrowing base or the Revolver Commitment Amount at any time. The Partnership intends to use proceeds from its best-efforts offering and cash flow from operations to meet its debt service requirements under the Credit Facility.

At closing, the Partnership borrowed $60.0 million. The proceeds were used to fund the purchase of Acquisition No. 2 described above and to pay closing costs. Subject to availability, the Credit Facility may also provide additional liquidity for future capital investments, including the drilling and completion of proposed wells by the operators of the Partnership’s properties, and other corporate working capital requirements. Under the terms of the Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells.

The Credit Facility contains mandatory prepayment requirements (including those described above), customary affirmative and negative covenants and events of default. The financial covenants as defined in the Loan Agreement include:

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

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 March 31, 2019, the Dealer Manager Incentive Fees are approximately $6.8 million, subject to Payout (defined below). As of March 31, 2019, the Partnership had completed the sale of 8.7 million common units for gross proceeds of approximately $170.9 million and proceeds net of offering costs of approximately $160.0 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:

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 months ended March 31, 2019 and 2018, the Partnership paid distributions of $0.349041 per common unit in both periods, or $2.8 million and $1.2 million, respectively. The Partnership generated $5.4 million in cash flow from operating activities for the three months ended March 31, 2019.

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.

Oil and Natural Gas Properties

The Partnership incurred approximately $11.2 million and $0.4 million in capital expenditures for the three months ended March 31, 2019 and for the period from February 1, 2018 to March 31, 2018. The Partnership expects to invest approximately $10.0 to $15.0 million in capital expenditures during the remainder of 2019, which includes approximately $8.0 to $10.0 million in anticipated capital costs to complete the 33 wells in process at March 31, 2019. In addition, the Partnership anticipates that it may be obligated to invest an additional $70 to $80 million in drilling capital expenditures from 2020 through 2023 to retain its approximate 6.0% working interest 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 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 2019. Current estimated capital expenditures could be significantly different from amounts actually invested.

The Partnership expects to fund overhead costs and capital additions related to the drilling and completion of wells primarily from proceeds from its ongoing best-efforts offering, cash provided by operating activities, cash on hand and availability, if any, under the Credit Facility. If an operator elects to complete drilling or other significant capital expenditure activity and the Partnership is unable to fund the capital expenditures, the General Partner may decide to farmout the well. Also, if a well is proposed under the operating agreement for one of the properties the Partnership owns, the General Partner may elect to “non-consent” the well. Non-consenting a well will generally cause the Partnership not to be obligated to pay the costs of the well, but the Partnership will not be entitled to the proceeds of production from the well until a penalty is received by the parties that drilled the well.

Subsequent Events

In April 2019, the Partnership declared and paid $0.9 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

In April 2019, the Partnership closed on the issuance of approximately 0.3 million common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $5.3 million and proceeds net of selling and marketing costs of approximately $4.9 million.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Information regarding the Partnership’s hedging programs to mitigate commodity risks is contained in Item 1 – Financial Statements (Unaudited) and Notes to Consolidated Financial Statements: Note 7. Risk Management and Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, appearing elsewhere within this Quarterly Report on Form 10-Q.

The Partnership also has a variable interest rate on its Credit Facility that is subject to market changes in interest rates. Information regarding the Partnership’s Credit Facility is contained in Item 1 – Financial Statements (Unaudited) and Notes to Consolidated Financial Statements: Note 5. Debt and Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, appearing elsewhere within this Quarterly Report on Form 10-Q.

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a–15 and 15d–15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Partnership carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, of the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of March 31, 2019 to provide reasonable assurance that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Partnership’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in the Partnership’s internal controls over financial reporting that occurred during the quarterly period ended March 31, 2019 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal controls over financial reporting.

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 2018 Annual Report on Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2018 Form 10-K. 

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

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 March 31, 2019, the Partnership had completed the sale of 8,677,363 common units for total gross proceeds of $170.9 million and proceeds net of offering costs including selling commissions and marketing expenses of $160.0 million. As of March 31, 2019, 8,954,216 common units remained unsold. The offering was extended in February 2019 and in accordance with the prospectus, the offering will expire on November 18, 2019, 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”) and is continuing 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 March 31, 2019, the Dealer Manager Incentive Fees are up to approximately $6.8 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 March 31, 2019.

Item 3.  Defaults upon Senior Securities.

Not applicable.

Item 4.  Mine Safety Disclosures.

Not applicable.

Item 5.  Other Information.

Not applicable.

Item 6.  Exhibits.

*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.