UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended June 30, 2020

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 August 13, 2020, 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.

Energy Resources 12, L.P.

Consolidated Statements of Partners’ Equity

(Unaudited)

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

June 30, 2020

(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, 2019, those described under Part II. Item 1A. Risk Factors included in this Form 10-Q 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, 2019.

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. 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 offering costs of $204.3 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 $90.5 million. 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 $81.3 million. 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 June 30, 2020, the Partnership’s ownership of the Bakken Assets consisted of an approximate 5.7% non-operated working interest in 347 producing wells, an estimated 2.7% non-operated working interest in 25 wells in various stages of the drilling and completion process and additional possible future development locations. Since September 1, 2017, the effective date of Acquisition No. 1, the Partnership has participated in the drilling of 175 wells.

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.

COVID-19, Current Oil Demand, Pricing and Production

Since first being reported in December 2019, COVID-19 has spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures have included significant restrictions on travel, forced quarantines, stay-in-place requirements and the closure of businesses in many industries, creating extreme volatility in capital markets and the global economy. Because of COVID-19’s impact to the global economy, demand for oil, natural gas and other hydrocarbons substantially declined in March and April 2020 and although market prices improved in May and June 2020, demand for oil and natural gas is not anticipated to return to pre-COVID-19 levels during 2020.

In addition to the outbreak of COVID-19 during the first quarter of 2020, Saudi Arabia and Russia, two of the largest worldwide producers of crude oil, engaged in a price war during March and April 2020. Russia did not participate in production cuts coordinated by the Organization of the Petroleum Exporting Countries (“OPEC”), which led to Saudi Arabia lowering crude oil prices and both countries substantially increasing daily output of crude oil. The increase in Saudi and Russian oil output along with sustained production by other global producers, including operators in the United States, has stressed the oil and gas industry’s capacity to store excess oil and gas. Despite Saudi Arabia, Russia, the United States and other OPEC members reaching an agreement in April 2020 to cut daily production, congested supply chain channels and excess crude oil and natural gas inventory are expected to weigh negatively on commodity prices while demand remains low during COVID-19.

These factors led to oil prices falling to 20-year lows in April 2020. The average daily NYMEX futures closing prices for the months of April, May and June 2020 were $16.70, $28.53 and $38.31, respectively. Although NYMEX oil prices stabilized in June 2020, prices remain below historical averages. With the anticipation that world-wide oil and natural gas prices would be depressed through at least the second quarter of 2020, the majority of the operators that operate the Bakken Assets on behalf of working interest owners like the Partnership announced reductions to their 2020 capital budgets, and as a result, new investment in the Partnership’s undrilled acreage is expected to be limited until commodity prices and market supply and demand imbalances become more favorable. In addition, because operators of the Bakken Assets were concerned they may not be able to sell produced oil and natural gas at an economical price point, along with the reduction in demand and the supply-strained storage facilities, many operators implemented other cost-cutting measures, including curtailing daily production and/or shutting in producing wells, during the second quarter of 2020. Approximately 25% of the Partnership’s producing wells were shut in for at least a portion of the second quarter of 2020. Although the majority of these wells have resumed production in June or July 2020, the Partnership experienced significant declines in its oil, natural gas and NGL production for the second quarter of 2020, resulting in an adverse impact to its cash flow from operations.

The Partnership’s revenues and cash flow from operations are highly sensitive to changes in oil and natural gas prices and to levels of production. Sustained lower prices along with reductions in produced and sold oil and natural gas volumes have and will continue to impact the amount of capital the Partnership has available for the development of its undrilled wellsites. Future growth is dependent on the Partnership’s ability to add reserves in excess of production. In addition to commodity price fluctuations, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.

The following table lists average NYMEX prices for oil and natural gas for the three and six months ended June 30, 2020 and 2019. 

Results of Operations

In evaluating financial condition and operating performance, the most important indicators on which the Partnership focuses are (1) total quarterly production in barrel of oil equivalent (“BOE”) units, (2) average sales price per unit for oil, natural gas and natural gas liquids (“NGL” or “NGLs”), (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 six months ended June 30, 2020 and 2019.

Oil, Natural Gas and NGL Revenues

For the three months ended June 30, 2020, revenues for oil, natural gas and NGL sales were $3.2 million. Revenues for the sale of crude oil were $3.0 million, which resulted in a realized price of $21.06 per barrel. Revenues for the sale of natural gas were $0.2 million, which resulted in a realized price of $1.26 per Mcf. Revenues for the sale of NGLs were approximately $3,000, which resulted in a realized price of $0.16 per BOE of production. For the three months ended June 30, 2019, revenues for oil, natural gas and NGL sales were $18.8 million. Revenues for the sale of crude oil were $18.1 million, which resulted in a realized price of $57.19 per barrel. Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $2.38 per Mcf. Revenues for the sale of NGLs were $0.3 million, which resulted in a realized price of $11.55 per BOE.

For the six months ended June 30, 2020, revenues for oil, natural gas and NGL sales were $15.1 million. Revenues for the sale of crude oil were $14.1 million, which resulted in a realized price of $34.97 per barrel. Revenues for the sale of natural gas were $0.7 million, which resulted in a realized price of $1.68 per Mcf. Revenues for the sale of NGLs were $0.3 million, which resulted in a realized price of $5.81 per BOE. For the six months ended June 30, 2019, revenues for oil, natural gas and NGL sales were $30.2 million. Revenues for the sale of crude oil were $28.8 million, which resulted in a realized price of $55.35 per barrel. Revenues for the sale of natural gas were $0.8 million, which resulted in a realized price of $2.78 per Mcf. Revenues for the sale of NGLs were $0.6 million, which resulted in a realized price of $12.97 per BOE.

The realized prices per barrel of oil above are based upon the NYMEX benchmark price less a cost to distribute the oil, or the differential. Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation methods out of the Bakken. Oil price differentials to the NYMEX benchmark price vary by operator based upon operator-specific contracts. Oil price differentials increased during the second quarter of 2020, compared to same period of 2019, due to oil supply produced in the Bakken exceeding demand and the storage capacity available at refineries. In July 2020, a federal judge ruled that two significant pipelines that transport oil and natural gas from North Dakota fields must suspend operations due to environmental review and disputes over right to use land owned by Native Americans (the ruling was later stayed on appeal). Therefore, the Partnership anticipates differentials may remain elevated during the remainder of 2020 so long as supply and demand imbalances are present as well as the potential suspension of these key pipelines in the region.

The Partnership’s results for the three and six months ended June 30, 2020 were negatively impacted by the Partnership’s realized sales prices for oil, natural gas and NGLs, which were negatively impacted by the significant decreases in market commodity prices described in “Current Price Environment” above, in comparison to the same periods of 2019. As noted above, approximately 25% of the Partnership’s wells were shut in for at least a portion of the second quarter of 2020. As operators of the Bakken Assets implemented cost-cutting measures throughout the second quarter of 2020, the Partnership’s sold production decreased to approximately 1,300 BOE per day in May 2020. The Partnership’s sold production for the Bakken Assets was approximately 2,100 BOE and 2,900 BOE per day for the three and six months ended June 30, 2020, respectively, compared to 4,100 BOE and 3,400 BOE per day for the same periods of 2019, respectively.

Realized sales prices for natural gas and NGLs were also negatively impacted in 2020 due to processing and transportation constraints, discussed above in “COVID-19, Current Oil Demand, Pricing and Production” and below in “Production Expenses”, as product leaves the region upon extraction and processing. If commodity prices fall from current levels and operators are unable to produce, process and sell oil and natural gas at economical prices, the operators of the Bakken Assets may continue or further curtail daily production, shut-in producing wells or seek other cost-cutting measures. Consequently, any of these measures could significantly impact the Partnership’s oil, natural gas and NGL production, and there can be no assurance regarding how they will produce if and when they are brought back on-line. Further, production is dependent on the investment in existing wells and the development of new wells. The Partnership has 25 wells currently in various stages of drilling and completion, and the timing of completion of these wells is unknown at this time. Therefore, the Partnership will experience natural production declines until market conditions improve and the 25 in-process wells are completed.

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 June 30, 2020 and 2019 were $2.8 million and $4.1 million, and production expenses per BOE were $15.20 and $10.86, respectively. Production expenses for the six months ended June 30, 2020 and 2019 were $7.7 million and $6.7 million, and production expenses per BOE were $14.60 and $10.87, respectively. Production expenses per BOE increased in the first half of 2020 in comparison to the first half of 2019 primarily due to the following: (i) a decrease in sold production volumes along with fixed lease operating expenses; (ii) a portion of the Partnership’s wells had tubing erosion due to extreme sand production, which required significant rework to return these wells to production; and (iii) the costs to gather, process and market the Partnership’s production, specifically natural gas and NGLs, have increased due to excess supply. The Partnership anticipates the costs to effectively gather, process and market its production per BOE of production will continue to be above prior year levels in the second half of 2020 if current market conditions continue.

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. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGLs to total sales. Production taxes for the three months ended June 30, 2020 and 2019 were $0.3 million (8% of revenue) and $1.7 million (9% of revenue), respectively. Production taxes for the six months ended June 30, 2020 and 2019 were $1.3 million (9% of revenue) and $2.7 million (9% of revenue), respectively.

Depreciation, Depletion, Amortization and Accretion (“DD&A”)

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. The Partnership’s DD&A for the three months ended June 30, 2020 and 2019 was $2.3 million and $4.3 million, and DD&A per BOE of production was $12.21 and $11.51, respectively. The Partnership’s DD&A for the six months ended June 30, 2020 and 2019 was $6.8 million and $7.1 million, and DD&A per BOE of production was $12.79 and $11.51, respectively.

The increase in DD&A expense per BOE of production for the three and six months ended June 30, 2020, compared to same periods of 2019, is primarily due to the Partnership’s investment in new wells during 2019 and 2020, of which 89 new wells have been completed since January 2019.

General and Administrative Costs

The principal components of general and administrative expense are accounting, legal, advisory and consulting fees. General and administrative costs for the three months ended June 30, 2020 and 2019 were $0.5 million in both periods. General and administrative costs for the six months ended June 30, 2020 and 2019 were $1.3 million in both periods.

Interest Income (Expense), net

Interest income, net for the three and six months ended June 30, 2020 was approximately $10,000 and $29,000, respectively. Interest expense, net for the three and six months ended June 30, 2019 was $0.5 million and $1.2 million. The primary component of Interest expense, net, during the three and six months ended June 30, 2019 was interest expense on the Partnership’s credit facility that was terminated in November 2019.

Gain (Loss) on Derivatives

Periodically, the Partnership has entered into derivative contracts with the objective to manage the commodity price risk on future oil and natural gas production.

The Partnership’s total net loss on derivatives for the three months ended June 30, 2020 was approximately $0.1 million, and the Partnership’s gain on derivatives for the six months ended June 30, 2020 was approximately $1.4 million. Based upon the change in estimated fair value of the Partnership’s derivative contracts (costless collars), the Partnership recorded a mark-to-market loss of approximately $1.0 million for the three months ended June 30, 2020, and a mark-to-market gain of approximately $0.2 million for the six months ended June 30, 2020. The Partnership recognized a gain of approximately $0.9 million on the settlement of derivative contracts that expired during the second quarter of 2020, calculated as the difference between the contract price and the market settlement price. The settled contracts represented 52,000 barrels of oil, resulting in a gain of $17.37 per barrel of oil. The Partnership recognized a gain of approximately $1.2 million on the settlement of derivative contracts that expired during the first half of 2020; the settled contracts represented 107,000 barrels of oil, resulting in a gain of $10.89 per barrel of oil.

The Partnership’s total net gain on derivatives for the three months ended June 30, 2019 was approximately $0.6 million, and the Partnership’s loss on derivatives for the six months ended June 30, 2019 was approximately $1.3 million. Based upon the change in estimated fair value of the Partnership’s derivative contracts (costless collars), the Partnership recorded a mark-to-market gain of approximately $0.7 million for the three months ended June 30, 2019, and a mark-to-market loss of approximately $1.2 million for the six months ended June 30, 2019. The Partnership recognized a net loss of approximately $0.1 million on the settlement of derivative contracts for the three and six months ended June 30, 2019. The settled contracts represented (i) 149,000 barrels of oil, resulting in a loss of $0.62 per barrel of oil, and (ii) 60,000 Mcf of produced natural gas, resulting in a gain of $0.06 per Mcf of natural gas. 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 Partnership did not enter into any new contracts during the second quarter of 2020 and had no outstanding contracts at June 30, 2020. The following table summarizes settlements on matured derivative instruments and non-cash gains or losses on open derivative instruments for the three and six months ended June 30, 2020 and 2019.

Supplemental Non-GAAP Measure

The Partnership uses “Adjusted EBITDAX”, defined as earnings (loss) before (i) interest (income) 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 six months ended June 30, 2020 and 2019.

Transactions with Related Parties

The Partnership has, and is expected to continue to engage in, significant transactions with related parties.  These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to existing related party transactions, as well as any new significant related party transactions.

See further discussion in “Note 7. Related Parties” in Part I, Item 1 of this Form 10-Q.

Liquidity and Capital Resources

With the completion of the Partnership’s best-efforts offering in October 2019 and extinguishment of the Partnership’s revolving credit facility in November 2019, the Partnership’s principal source of liquidity are cash on-hand and the cash flow generated from the properties the Partnership owns. The Partnership anticipates that cash on-hand and cash flow from operations will be adequate to meet its liquidity requirements for at least the next 12 months, including completing the outstanding capital expenditures discussed below. Although the Partnership anticipates its cash on-hand and cash flow from operations to be adequate to fund its cash requirements, if market prices for oil and natural gas remain depressed and production from Partnership wells remains low due to cost-cutting measures taken by the Partnership’s operators, the Partnership’s cash flow from operations may further decline, which could have a significant impact on the Partnership’s available cash on-hand as well as the Partnership’s ability to fund distributions to its limited partners and/or participate in future drilling programs as proposed by the operators of the Bakken Assets.

Partners’ Equity

The Partnership completed its best-efforts offering of common units on October 24, 2019. As of the conclusion of the offering, 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 offering costs of $204.3 million.

Under the 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 (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, 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 six months ended June 30, 2020, the Partnership paid distributions of $0.349041 and $0.698082 per common unit, or $3.9 million and $7.7 million, respectively. For the three and six months ended June 30, 2019, the Partnership paid distributions of $0.349041 and $0.698082 per common unit, or $3.1 million and $6.0 million, respectively. The Partnership generated $11.8 million and $14.8 million in cash flow from operating activities for the six months ended June 30, 2020 and 2019, respectively.

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 and capital expenditures for new wells. In light of recent global economic volatility and a low commodity price environment, as discussed in the “COVID-19, Current Oil Demand, Pricing and Production” section above, there can be no assurance as to the classification or duration of distributions at the current distribution rate of $1.40 per common unit per year. If distributions are not paid or are reduced, the difference to the current distribution rate of $1.40 per common unit will be deferred and is required to be paid before final Payout occurs, as discussed above.

Oil and Natural Gas Properties

The Partnership incurred approximately $3.1 million and $21.9 million in capital expenditures for the six months ended June 30, 2020 and 2019. As discussed above, the Partnership has 25 wells in various stages of the drilling and completion process, and the Partnership estimates its share of capital expenditures to complete those 25 wells is approximately $2 to $4 million. Further, the Partnership has elected to participate in the drilling of an additional five wells that have not yet commenced drilling as of June 30, 2020. The Partnership’s estimated share of capital expenditures to complete these five wells is approximately $3 to $4 million. Because of the uncertainty surrounding global markets stemming from the COVID-19 pandemic and low commodity pricing due to excess supply and reduced demand, it is difficult to predict the amount and timing of capital expenditures for the remainder of 2020 and estimated capital expenditures could be significantly different from amounts actually invested.

Based upon current information from its operators, development during the first half of 2020 and a reduction in commodity prices, the Partnership updated its future drilling schedule by operator for its June 30, 2020 reserves estimate. These updates reduced the number of wells classified as proved undeveloped reserves (“PUD”) at June 30, 2020 by approximately 10%, but the change to overall PUD reserve quantities was minimal. In addition to the $2 to $3 million in estimated capital expenditures for 2020 to complete in-process wells, the Partnership anticipates that it may be obligated to invest $65 to $75 million in capital expenditures from 2021 through 2024 to participate in new well development without becoming subject to non-consent penalties under the joint operating agreements governing the Bakken Assets. If there are any additional changes to operator capital investment plans or delays in the development of PUD reserves, the Partnership may be required to reclassify PUD locations and the associated reserves which are no longer projected to be drilled within five years to non-proved reserves.

The Partnership expects to fund overhead costs and capital additions related to the drilling and completion of wells primarily from proceeds from cash provided by operating activities and cash on hand. 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 July 2020, the Partnership declared and paid $1.5 million, or $0.134247 per outstanding common unit, in distributions to its holders of common units.

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 5. 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.

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a–15 and 15d–15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Partnership carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, of the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of June 30, 2020 to provide reasonable assurance that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Partnership’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in the Partnership’s internal controls over financial reporting that occurred during the quarterly period ended June 30, 2020 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

The Partnership’s potential risks and uncertainties are discussed in Item 1A. Risk Factors in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2019. The information below updates, and should be read in conjunction with, the risk factors and information disclosed in the Partnership’s 2019 Form 10-K. Except as presented below, there have been no material changes from the risk factors described in our 2019 Form 10-K.

The current widespread outbreak of COVID-19 has significantly adversely impacted and disrupted, and is expected to continue to adversely impact and disrupt, the Partnership’s business and the industry in which the Partnership operates.

In December 2019, China reported an outbreak of a novel coronavirus (“COVID-19”) in its Wuhan province. On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States declared a national emergency with respect to COVID-19. COVID-19 has spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures include significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries, creating extreme volatility in capital markets and the global economy.

COVID-19’s impact to the global economy, in particular the oil and gas industry, has been unprecedented, as reduced demand for fossil fuels has resulted in a significant decline in commodity prices during March and April 2020. The Partnership experienced a decline in anticipated revenue during March 2020 and the second quarter of 2020 due to commodity price declines, and the Partnership expects demand for oil and gas as well as commodity prices to be low for the remainder of 2020, which will negatively impact the Partnership’s business during the second half of 2020 and likely beyond. The Partnership cannot give any assurance as to when demand will return to more normal levels or if commodity prices will increase.

The COVID-19 pandemic and related restrictions aimed at mitigating its spread have caused the General Partner to modify certain of the Partnership’s business practices, including limiting employee travel, encouraging work-from-home practices and other social distancing measures. Such measures may cause disruptions to the Partnership’s business and operational plans, which may include shortages of employees, contractors and subcontractors. There is no certainty that these or any other future measures will be sufficient to mitigate the risks posed by the disease, including the risk of infection of key employees, and the Partnership’s ability to perform certain functions could be impaired by these new business practices. For example, the Partnership’s reliance on technology has necessarily increased due to the General Partner’s encouragement of remote communications and other work-from-home practices, which could make the Partnership more vulnerable to cyber-attacks.

The spread of COVID-19 has caused severe disruptions in the global economy, specifically the oil and gas industry, and could potentially create widespread business continuity issues of an as yet unknown magnitude and duration.

COVID-19 has caused severe economic, market and other disruptions worldwide. In many respects, it is too early to quantify the long-term ramifications of COVID-19 on the global economy as well as oil and gas industry, the Partnership’s operators and the Partnership’s business. Further, it is currently not possible to predict how long the COVID-19 pandemic will last or the time that it will take for economic activity to return to prior levels. As a result, the Partnership cannot provide an estimate of the overall impact of COVID-19 on its business or when, or if, the Partnership and its operators will be able to resume normal, pre-COVID-19 operations. Nevertheless, sustained lower oil and gas prices and reduced demand resulting from COVID-19 present material uncertainty and risk with respect to the Partnership’s business, financial performance and condition, operating results and cash flows. In addition, low oil and natural gas prices may cause the Partnership’s undrilled wellsites to become uneconomic to develop.

Crude oil prices declined significantly in the first quarter of 2020 and into the second quarter of 2020. If oil prices remain at current levels or decline further for a prolonged period, the Partnership’s operations and financial condition may be materially and adversely affected.

In the first quarter of 2020 and through the beginning of the second quarter, crude oil prices fell sharply and dramatically, due in part to significantly decreased demand as a result of COVID-19 and the significantly increased supply of crude oil as a result of a price war between Saudi Arabia and Russia. In April 2020, Saudi Arabia, Russia, the United States and other members of OPEC agreed to certain production cuts; however, these cuts are not expected to be enough to offset near-term demand loss attributable to COVID-19. Prices for WTI crude oil were over $60 per barrel at the beginning of 2020 before declining significantly through March and further declined as prices fell below $20 per barrel by the end of April 2020. If crude oil prices remain at current levels or further decline for a prolonged period, the Partnership’s operations, financial condition, cash flows, level of expenditures and the quantity of estimated proved reserves that may be attributed to the Partnership’s properties may be materially and adversely affected.

As domestic demand for crude oil has declined substantially due to the COVID-19 pandemic, the General Partner cannot ensure that there will be a physical market for the Partnership’s production at economic prices until markets stabilize.

As a result of low commodity prices, the operators of the Partnership’s wells have and may curtail a portion of the Partnership’s estimated crude oil production and may store rather than sell additional crude oil production in the near future. Additionally, the excess supply of oil could lead to further curtailments by those operators. While the Partnership believes that the shutting-in of such production will not impact the productivity of such wells when reopened, there is no assurance the Partnership will not have a degradation in well performance upon returning those wells to production. The storing or shutting in of a portion of the Partnership’s production can also result in increased costs under midstream and other contracts. Any of the foregoing could result in an adverse impact on the Partnerships revenues, financial position and cash flows.

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

Not applicable.

Item 3.  Defaults upon Senior Securities.

Not applicable.

Item 4.  Mine Safety Disclosures.

Not applicable.

Item 5.  Other Information.

Not applicable.

Item 6.  Exhibits.

*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.