UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

FORM 10-Q 

For the quarterly period ended September 30, 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 October 31, 2019, the Partnership had 11,031,579 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

September 30, 2019

(Unaudited)

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 began offering common units of limited partner interest (the “common units”) on a best-efforts basis on May 17, 2017, the date the Partnership’s initial Registration Statement on Form S-1 (File No. 333-216891) was declared effective by the Securities and Exchange Commission. As of July 25, 2017, the Partnership completed the sale of the minimum offering of common units for gross proceeds of approximately $25 million. The Partnership completed its best-efforts offering on October 24, 2019. Total common units sold were approximately 11.0 million for gross proceeds of $218.0 million and proceeds net of selling commissions and marketing expenses of $204.9 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. 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 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 September 30, 2019, the Partnership had an approximate 5.9% non-operated working interest in 321 currently producing wells. The Partnership also owned non-operated working interests in 27 wells in various stages of the drilling and completion process and additional future development locations in the Bakken Assets. 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

Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control. Historically, worldwide oil and natural gas prices and markets have been subject to significant change and may continue to be in the future. Factors contributing to worldwide 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 145 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 and nine months ended September 30, 2019 and 2018, as discussed below, are 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 and nine months ended September 30, 2019 and 2018.

Oil, Natural Gas and NGL Revenues

For the three months ended September 30, 2019, revenues for oil, natural gas and NGL sales were $15.9 million. Revenues for the sale of crude oil were $15.4 million, which resulted in a realized price of $54.14 per barrel. Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $1.96 per Mcf. Revenues for the sale of NGLs were $0.1 million, which resulted in a realized price of $2.96 per BOE. For the three months ended September 30, 2018, revenues for oil, natural gas and NGL sales were $5.5 million. Revenues for the sale of crude oil were $5.1 million, which resulted in a realized price of $68.19 per barrel. Revenues for the sale of natural gas were $0.3 million, which resulted in a realized price of $3.59 per Mcf. Revenues for the sale of NGLs were $0.2 million, which resulted in a realized price of $24.32 per BOE of production.

For the nine months ended September 30, 2019, revenues for oil, natural gas and NGL sales were $46.1 million. Revenues for the sale of crude oil were $44.2 million, which resulted in a realized price of $54.92 per barrel. Revenues for the sale of natural gas were $1.2 million, which resulted in a realized price of $2.46 per Mcf. Revenues for the sale of NGLs were $0.7 million, which resulted in a realized price of $8.89 per BOE. For the eight months from February 1, 2018 to September 30, 2018, revenues for oil, natural gas and NGL sales were $16.5 million. Revenues for the sale of crude oil were $15.3 million, which resulted in a realized price of $64.42 per barrel. Revenues for the sale of natural gas were $0.6 million, which resulted in a realized price of $2.98 per Mcf. Revenues for the sale of NGLs were $0.6 million, which resulted in a realized price of $21.92 per BOE of production.

The Partnership’s results during the first three quarters of 2019 were positively impacted by the completion of over 75 wells by the Partnership’s operators since June 30, 2018, which contributed to increases in the Partnership’s sold production volumes of oil, natural gas and NGL during the first three quarters of 2019, in comparison to first three quarters of 2018. The Partnership’s sold production for the Bakken Assets was approximately 3,800 BOE and 3,500 BOE per day for the three and nine months ended September 30, 2019. If the Partnership had completed Acquisitions No. 1 and No. 2 on January 1, 2018, the Partnership estimates sold production for the Bakken Assets would have been approximately 1,800 BOE and 2,300 BOE per day for the three and nine months ended September 30, 2018. Production volumes per day fluctuate due to the timing of well completions; new wells often have high levels of production immediately following completion, then decline to more consistent levels.

Sold production increases realized during the first three quarters of 2019 were partially offset by the Partnership’s realized sales prices for oil, natural gas and NGL, which were negatively impacted by decreases in commodity prices for oil, natural gas and NGLs, in comparison to the first three quarters of 2018. Realized sales prices for natural gas and NGLs for the first three quarters of 2019 were also negatively impacted by processing and transportation constraints, discussed below in Production Expenses, as product leaves the Bakken basin.

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 27 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 September 30, 2019 and 2018 were $4.4 million and $0.9 million, respectively, and production expenses per BOE were $12.72 and $10.09, respectively. Production expenses for the nine months ended September 30, 2019 and for the eight months from February 1, 2018 to September 30, 2018 were $11.1 million and $3.2 million, respectively, and production expenses per BOE were $11.54 and $10.67, respectively. Higher costs for gathering, processing, transporting and marketing the natural gas and NGL products along with higher workover expenses to maintain well performance contributed to the increase in the Partnership’s production expenses per BOE during the three and nine months ended September 30, 2019, when compared to the same periods in 2018.

Production Taxes

Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. Production taxes for the three months ended September 30, 2019 and 2018 were $1.4 million (9.0% of revenue) and $0.5 million (10.0% of revenue). Production taxes for the nine months ended September 30, 2019 and for the eight months from February 1, 2018 to September 30, 2018 were $4.2 million (9.0% of revenue) and $1.5 million (9.0% of revenue). Taxes on the sale of gas and NGL products are less than taxes levied on the sale of oil. The increase in production taxes incurred during the three- and nine-month periods ended September 30, 2019, compared to the same periods of 2018, is the direct result of increased sold production volumes.

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 September 30, 2019 and 2018 was $4.2 million and $1.0 million, respectively, and DD&A per BOE of production was $12.04 and $10.93, respectively. The Partnership’s DD&A for the nine months ended September 30, 2019 and for the eight months from February 1, 2018 to September 30, 2018 was $11.3 million and $3.0 million, respectively, and DD&A per BOE of production was $11.70 and $10.10. The increase in DD&A expense per BOE of production during the three and nine months ended September 30, 2019, compared to the same periods of 2018, is primarily due to the Partnership’s investment in new wells. As discussed above, the Partnership’s operators have completed over 75 wells since June 30, 2018.

General and Administrative Costs

The principal components of general and administrative expense are accounting, legal, advisory, consulting and management fees. General and administrative costs for the three months ended September 30, 2019 and 2018 were $0.5 million and $0.4 million, respectively. General and administrative expenses for the nine months ended September 30, 2019 and 2018 were $1.8 million and $1.1 million, respectively. General and administrative costs for the three and nine months ended September 30, 2019 exceeded those of the comparable periods of 2018 due to the Partnership raising funds through its best-efforts offering (increases in funds raised increases the management fee due to the General Partner) as well as an increase in accounting, consulting and advisory fees resulting from the Partnership’s acquisitions of non-operated working interest in the Bakken Assets in February and August 2018.

Interest Expense, net

Interest expense, net for the three months ended September 30, 2019 and 2018 was $0.3 million and $0.5 million, respectively. Interest expense, net for the nine months ended September 30, 2019 and 2018 was $1.5 million and $0.9 million, respectively. The primary component of Interest expense, net, through the first three quarters of 2019 was interest expense on the Credit Facility, while the primary component of Interest expense, net, through the first three quarters of 2018 was interest expense on the Credit Facility and the Term Loan, as discussed below in Liquidity and Capital Resources: Financing.

Gain (Loss) on Derivatives

Periodically, the Partnership enters into derivative contracts with the objective to manage the commodity price risk on future oil and natural gas production. The Partnership’s gain on derivative instruments for the three months ended September 30, 2019 was approximately $0.6 million. The gain was comprised of (i) a $0.6 million mark-to-market unrealized gain on derivative instruments outstanding at period end, and (ii) $9,600 in gains on settled derivatives during the period. The Partnership’s recognized gains on settled derivatives of $9,600 represented 50,000 Mcf of produced natural gas, resulting in a gain of $0.19 per Mcf of natural gas.

The Partnership’s loss on derivative instruments for the nine months ended September 30, 2019 was approximately $0.7 million. The loss was comprised of (i) a $0.6 million mark-to-market unrealized loss incurred on derivative instruments outstanding at period end, and (ii) $0.1 million of net losses on settled derivatives during the period. The Partnership’s recognized losses on settled derivatives of $0.1 million, net, represented (i) 219,000 barrels of produced oil, resulting in a loss of $0.42 per barrel of oil and (ii) 110,000 Mcf of produced natural gas, resulting in a gain of $0.12 per Mcf of natural gas. The Partnership’s derivative contracts tied to oil production that expired during the first and third quarters 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 Partnership’s loss on derivative instruments for the three and nine months ended September 30, 2018 was approximately $57,000, which represented a mark-to-market unrealized loss on derivative instruments outstanding at period end.

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 gains or losses recorded by the Partnership do not represent actual settlements.

See Note 5. Debt in the Partnership’s Unaudited Consolidated Financial Statements and Notes thereto, appearing elsewhere in this Quarterly Report on Form 10-Q, for additional information regarding the Partnership’s responsibility to maintain a risk management program if certain conditions are met under the Loan Agreement.

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 and nine months ended September 30, 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

With the completion of the Partnership’s best-efforts offering in October 2019, the Partnership’s principal sources of liquidity will be cash on-hand, 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 and availability under the revolving credit facility will be adequate to meet its liquidity requirements for at least the next 12 months, including completing capital expenditures discussed below. If these sources of funds are insufficient, the Partnership 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, 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 “Initial 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 Initial Revolver Commitment Amount, or $300,000. The commitment amount was $40 million (“Revolver Commitment Amount”) at September 30, 2019, and the Partnership 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. Any outstanding borrowings under the Credit Facility cannot exceed the lesser of the borrowing base or the Revolver Commitment Amount at any time; the effective borrowing base and the Revolver Commitment Amount were both $40 million at September 30, 2019. As of September 30, 2019, the outstanding balance on the Credit Facility was $0.

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.

If certain conditions set forth in the Loan Agreement, as amended, are met, the Partnership will be required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production. If these conditions are met, the risk management program must cover at least 50% of the Partnership’s projected total production of oil and natural gas for a rolling 18-month period.

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 September 30, 2019.
  

Partners’ Equity

The Partnership completed its best-efforts offering of common units on October 24, 2019. The Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit on July 25, 2017. All subsequent common units were sold at $20.00 per common unit. As of September 30, 2019, the Partnership had completed the sale of 10.7 million common units for gross proceeds of approximately $212.3 million and proceeds net of offering costs of approximately $198.9 million. As of the conclusion of the offering on October 24, 2019, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of selling commissions and marketing expenses of $204.9 million.

Under the Partnership’s agreement with the Managing Dealer of its best-efforts offering, the Managing Dealer received 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 the conclusion of the offering on October 24, 2019, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (defined below).

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 and nine months ended September 30, 2019, the Partnership paid distributions of $0.349041 and $1.047123 per common unit, or $3.5 million and $9.5 million, respectively. For the three and nine months ended September 30, 2018, the Partnership paid distributions of $0.349041 and $1.047123 per common unit, or $2.0 million and $4.6 million, respectively. The Partnership generated $26.3 million and $6.8 million in cash flow from operating activities for the nine months ended September 30, 2019 and 2018, respectively.

The Partnership’s ability to maintain the current distribution of $1.40 per common unit per year will be based on its ability to maintain or increase cash flow from operating activities. While the Partnership’s goal is to maintain a relatively stable distribution rate over the life of its program, the General Partner monitors monthly Partnership distributions in conjunction with the Partnership’s projected cash requirements for operations, capital expenditures for new wells and debt service.

Oil and Natural Gas Properties

The Partnership incurred approximately $28.2 million and $5.6 million in capital expenditures for the nine months ended September 30, 2019 and for the eight-month period from February 1, 2018 to September 30, 2018, respectively. The Partnership expects to invest a total of approximately $10 to $15 million in capital expenditures during the fourth quarter of 2019 and first quarter of 2020, which includes anticipated capital costs to complete the 27 wells in process at September 30, 2019. In addition, the Partnership anticipates that it may be obligated to invest an additional $65 to $75 million in drilling capital expenditures from 2020 through 2023 to participate in new well development 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 and into 2020. Current estimated capital expenditures could be significantly different from amounts actually invested.

The Partnership expects to fund overhead costs and capital additions related to the drilling and completion of wells primarily from cash provided by operating activities, cash on hand and availability, 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 October 2019, the Partnership declared and paid $1.2 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

On October 24, 2019, the Partnership closed on the issuance of approximately 0.3 million common units through its best-efforts offering, representing gross proceeds to the Partnership of approximately $5.7 million and proceeds net of selling and marketing costs of approximately $5.4 million. On October 25, 2019, the General Partner terminated the Partnership’s best-efforts offering and deregistered the remaining 6.6 million common units that were not sold under the best-efforts offering. As of the close of business on October 24, 2019, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of selling commissions and marketing expenses of $204.9 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 September 30, 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 September 30, 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 offered common units of limited partner interest (the “common units”) on a best-efforts basis. The maximum offering was $350,000,001, consisting of 17,631,579 common units. As of September 30, 2019, the Partnership had completed the sale of 10,745,057 common units for total gross proceeds of $212.3 million and proceeds net of offering costs including selling commissions and marketing expenses of $198.9 million. As of September 30, 2019, 6,886,522 common units remained unsold. The Partnership’s offering of common units of limited partner interest was completed on October 24, 2019. Upon completion, the Partnership had sold approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of selling commissions and marketing expenses of $204.9 million.

Under the Partnership’s agreement with the Managing Dealer, the Managing Dealer received 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 October 24, 2019, the Dealer Manager Incentive Fees are up to approximately $8.7 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 best-efforts offering and the use of proceeds from the offering as of September 30, 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.