10-K 1 er1220181231_10k.htm FORM 10-K er1220181231_10k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

 


 

FORM 10-K

 


 

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

 

For the fiscal year ended December 31, 2018

 

OR

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

 

Commission File Number 000-55916

 

Energy Resources 12, L.P.

(Exact name of registrant as specified in its charter) 

Delaware

81-4805237

(State or other jurisdiction

of incorporation or organization)

(IRS Employer

Identification No.)

 

 

120 W 3rd Street, Suite 220

Fort Worth, Texas

76102

(Address of principal executive offices) 

(Zip Code)

 

(817) 882-9192

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Exchange Act: None

 

Securities registered pursuant to Section 12(g) of the Exchange Act: Common Units of Limited Partnership Interest

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐  No ☑

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐  No ☑

 

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☑

 

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

 

Large accelerated filer   ☐

 

 

 

Accelerated filer ☐

Non-accelerated filer     ☐ 

 

 

 

Smaller reporting company   ☑

Emerging growth company   ☑

 

 

 

 

 

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

 

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

 

There is no established public market for the registrant’s outstanding limited partnership interests. The aggregate market value of the registrant’s limited partnership interests held by non-affiliates of the registrant as of June 30, 2018 was $0.

 

As of March 29, 2019, the Partnership had 8,677,363 common units outstanding.

 

 

 

Energy Resources 12, L.P.

Form 10-K

Index

 

 

 

Page

Part I

 

 

Item 1. Business

4

 

Item 1A. Risk Factors

20

 

Item 1B. Unresolved Staff Comments

42

 

Item 2. Properties

42

 

Item 3. Legal Proceedings

42

 

Item 4. Mine Safety Disclosures

42

Part II

 

 

Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

43

 

Item 6. Selected Financial Data

44

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

45

 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

54

 

Item 8. Financial Statements and Supplementary Data

55

 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

75

 

Item 9A. Controls and Procedures

75

 

Item 9B. Other Information

75

Part III

 

 

Item 10. Directors, Executive Officers and Corporate Governance

76

 

Item 11. Executive Compensation

78

 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

78

 

Item 13. Certain Relationships and Related Transactions, and Director Independence

80

 

Item 14. Principal Accounting Fees and Services

82

Part IV

 

 

Item 15. Exhibits, Financial Statement Schedules

83

 

Item 16. Form 10-K Summary

85

 

 

 

Signatures

86

 

 

 

Part I

 

FORWARD LOOKING STATEMENTS

 

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:

 

investment objectives and the Partnership’s ability to make investments in a timely manner on acceptable terms;

references to future success in the Partnership’s property acquisition, drilling and marketing activities;

the Partnership’s use of proceeds of the public offering and its business strategy;

estimated future capital expenditures;

estimated future distributions;

sales of the Partnership’s properties and other liquidity events;

competitive strengths and goals; and

other similar matters.

 

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

 

that the Partnership’s strategy of acquiring oil and gas properties on attractive terms and developing those properties may not be successful or that its operations on such properties may not be successful;

general economic, market, or business conditions;

changes in laws or regulations;

the risk that the wells in which the Partnership acquires an interest are productive, but do not produce enough revenue to return the investment made;

the risk that the wells the Partnership drills do not find hydrocarbons in commercial quantities or, even if commercial quantities are encountered, that actual production is lower than expected on the productive life of wells is shorter than expected;

current credit market conditions and the Partnership’s ability to obtain long-term financing for its property acquisitions and drilling activities in a timely manner and on terms that are consistent with what the Partnership projects when it invests in a property;

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

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

 

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

 

 

 

Item 1.  Business

 

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 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. As of December 31, 2018, the Partnership had sold approximately 7.9 million common units for gross proceeds of $154.5 million and proceeds net of offering costs of $144.6 million. In February 2019, the Partnership extended the offering until November 18, 2019; the offering will expire on November 18, 2019 or the sale of 17,631,579 common units, whichever occurs first. As of March 29, 2019, the Partnership had approximately 8.7 million common units outstanding and approximately 9.0 million common units remain unsold.

 

As of December 31, 2018, the Partnership owned an approximate 5.9% non-operated working interest in 257 currently producing wells and 37 wells in various stages of the drilling and completion process, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 14 third-party operators on behalf of the Partnership and other working interest owners.

 

The general partner of the Partnership is Energy Resources 12 GP, LLC (the “General Partner”).

 

Business Objective

 

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

 

Current Developments

 

On February 1, 2018, the Partnership completed its first purchase (“Acquisition No. 1”) in the Bakken Assets for approximately $87.5 million, subject to customary adjustments. On August 31, 2018, the Partnership completed its second purchase (“Acquisition No. 2”) of an additional non-operated working interest in the Bakken Assets for approximately $82.5 million, subject to customary adjustments. The Partnership utilized proceeds from its ongoing best-efforts offering and available financing to close on Acquisitions No.1 and No. 2. Prior to these acquisitions, the Partnership owned no oil and natural gas assets. The Bakken Assets are operated by 14 third-party operators on behalf of the Partnership and other working interest owners, including WPX Energy (NYSE: WPX), Marathon Oil (NYSE: MRO), EOG Resources (NYSE: EOG), Continental Resources (NYSE: CLR) and RimRock Oil and Gas. 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.

 

Market Update

 

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”). Factors contributing to uncertainty within the industry 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.

 

4

 

Since February 2018, monthly average oil prices (based on daily settlements of monthly contracts traded on the NYMEX) ranged from a low of $48.97 per barrel in December 2018 to a high of $70.98 in July 2018. The monthly average of $70.98 per barrel of oil in July 2018 represented the highest monthly average since November 2014. Since February 2018, monthly averages for natural gas prices have ranged from $2.67 per MMBtu in February 2018 to $4.09 per MMBtu in November 2018.

 

Production, Prices and Production Cost History

 

The following table sets forth certain information regarding the production volumes, average prices received and average production costs associated with the sale of oil, natural gas, and natural gas liquids for the period from the Partnership’s first acquisition on February 1, 2018 through December 31, 2018.

 

   

Eleven Months Ended

December 31,

 
   

2018

 
         

Sold production (BOE):

       

Oil

    405,581  

Natural gas

    53,240  

Natural gas liquids

    42,329  

    Total

    501,150  
         

Average sales price per unit:

       

Oil (per Bbl)

  $ 58.66  

Natural gas (per Mcf)

    3.30  

Natural gas liquids (per Bbl)

    20.73  

Combined (per BOE)

    51.32  
         

Average unit cost per BOE:

       

Production costs

       

    Production expenses

    11.36  

    Production taxes

    4.58  

Total production costs

    15.94  

Depreciation, depletion, amortization and accretion

    9.83  

 

Drilling Activity

 

Since closing on Acquisition No. 1 on February 1, 2018 through December 31, 2018, the Partnership incurred approximately $15.4 million in capital drilling and completion costs. Since September 1, 2017, the effective date of Acquisition No. 1, the Partnership has participated in the drilling of 93 wells, of which 56 have been completed and 37 wells are in various stages of completion at December 31, 2018.

 

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”).

 

5

 

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 December 31, 2018, the Lender commitment was $40.0 million and the interest rate for the Credit Facility was approximately 6.25%. At December 31, 2018, the outstanding balance on the Credit Facility was $39.5 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.

 

Related Parties

 

The Partnership has, and is expected to continue to engage in, significant transactions with related parties, including those discussed below. 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.

 

Regional Energy Investors, LP

 

In November 2017 and June 2018, the Partnership engaged Regional Energy Investors, LP (“REI”) to perform advisory and consulting services, including supporting the Partnership through closing and post-closing on the purchase of certain oil and gas properties in North Dakota. REI is owned by entities that are controlled by Anthony F. Keating, III and Michael J. Mallick, Co-Chief Operating Officers of Energy 11 GP, LLC, the general partner of Energy 11, G.P. (“Energy 11”). Glade M. Knight and David S. McKenney are the Chief Executive Officer and Chief Financial Officer, respectively, of the General Partner as well as the Chief Executive Officer and Chief Financial Officer, respectively, of Energy 11 GP, LLC. In December 2018, the agreements with REI were terminated, which extinguished any potential fees payable to REI by the Partnership upon a sale of certain of the Partnership’s assets. In connection with the termination, entities controlled by Messrs. Keating and Mallick acquired a non-voting interest in the General Partner.

 

Cost Sharing Agreement

 

On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11 to provide access to Energy 11’s personnel and administrative resources. The personnel provide accounting, asset management and other day-to-day management support for the Partnership. 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 for Energy 11. The agreement may be terminated at any time by either party upon 60 days written notice.

 

See further discussion in Note 8. Related Parties in Part II, Item 8 of this Form 10-K.

 

Partners’ Equity and Distributions

 

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.

 

6

 

As of July 25, 2017, the Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit. On October 6, 2017, the Partnership had received subscriptions for all of the common units offered at $19.00 (2,631,579), and consequently all common units offered and sold after October 6, 2017 have been and will be sold at $20.00 per common unit. As of December 31, 2018, the Partnership had completed the sale of approximately 7.9 million common units for gross proceeds of approximately $154.5 million and proceeds net of offering costs of approximately $144.6 million. The Partnership continues to raise capital through its best-efforts offering of common units by David Lerner Associates, Inc. (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 December 31, 2018, the Dealer Manager Incentive Fees are approximately $6.2 million, subject to Payout (defined below).

 

Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units.  Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.

 

The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

 

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

 

 

First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

 

 

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

 

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

 

For the year ended December 31, 2018, the Partnership paid distributions of $1.396164 per common unit, or $7.0 million. For the year ended December 31, 2017, the Partnership paid distributions of $0.598357 per common unit, or $1.5 million. The Partnership began paying distributions upon reaching the minimum offering in July 2017.

 

Oil and Natural Gas Reserves

 

The table below summarizes the Partnership’s estimated net proved reserves as of December 31, 2018:

 

   

Oil

   

Natural Gas

   

NGLs

   

Total

   

Standardized
Measure (2)

 
   

(MBbls)

   

(MMcf)

   

(MBbls)

   

(MBOE)

   

(in thousands)

 

Proved Reserves (1)

                                       

Developed

    6,982       4,127       687       8,357     $ 171,737  

Undeveloped

    13,282       5,836       805       15,060       198,758  

Total Proved Reserves

    20,264       9,963       1,492       23,417     $ 370,495  

 

 

7

 


 

(1)

 

The Partnership’s proved reserves as of December 31, 2018 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on unweighted arithmetic average prices as of the first day of each of the twelve months ended on such date. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2018 were $65.56 per barrel of oil and $3.10 per MMcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2018 were $59.56 per barrel of oil, $2.43 per MMcf of natural gas and $20.25 per barrel of NGL. See “Note 9 — Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)” in the accompanying notes to consolidated financial statements included elsewhere in this report for information concerning proved reserves.

 

 

 

 

 

(2)

 

The standardized measure of discounted future net cash flows represents the estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation, in accordance with Accounting Standards Codification Topic 932 – Extractive Activities – Oil and Gas. Because the Partnership was formed as a limited partnership, the Partnership is not subject to federal taxes in the calculation of the standardized measure. In addition, there are no entity level or gross receipts taxes in North Dakota, where all Partnership wells are located, that would give rise to an additional state tax provision.

 

The table above represents estimates only. Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. In addition, the Partnership may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond its control. Prices for oil or natural gas at December 31, 2018 are below the average calculated for 2018. Sustained lower prices will have a negative impact to the estimated quantities and present values of the Partnership’s reserves and may necessitate future write-downs.

 

Proved Undeveloped Reserves

 

At December 31, 2018, the Partnership had proved undeveloped reserves (“PUDs”) of approximately 15,060 MBOE, or approximately 64% of total proved reserves. The following table reflects the changes in PUDs during 2018:

 

   

BOE

 

Proved undeveloped reserves, December 31, 2017

    -  

Proved undeveloped reserves acquired, February 1, 2018 (1)

    8,427,708  

Proved undeveloped reserves acquired, August 31, 2018 (2)

    7,279,846  

Revisions of previous estimates (3)

    1,252,630  

Conversion to proved developed reserves (4)

    (1,899,972

)

Proved undeveloped reserves, December 31, 2018

    15,060,212  

 


 

(1)

 

The Partnership acquired 8,428 MBOE attributable to PUDs in conjunction with Acquisition No. 1.

 

(2)

 

The Partnership acquired 7,280 MBOE attributable to PUDs in conjunction with Acquisition No. 2.

 

(3)

 

Revisions to previous estimates, from the respective closing dates for Acquisitions No. 1 and No. 2, increased PUDs by a net amount of 1,253 MBOE. These revisions result from 1,249 MBOE of upward adjustments attributable to changes in the future drill schedule and 4 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2018 to oil, natural gas and NGL prices at the dates of Acquisitions No. 1 and No. 2. There were no adjustments related to well performance.

 

(4)

 

Since the Partnership completed its first acquisition, 56 wells have either been completed or are in-process by the Partnership’s operators. This development has led to 1,900 MBOE of PUDs being converted to proved developed reserves from February 1, 2018 to December 31, 2018.

 

8

 

Under current SEC requirements, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of their date of original booking unless specific circumstances justify a longer time. The Partnership will be required to remove current PUDs if the Partnership does not drill those reserves within the required five-year time frame, unless specific circumstances justify a longer time. All of the Partnership’s PUDs at December 31, 2018 are scheduled to be drilled within five years of the date they were initially recorded. However, since the Partnership is not the operator of any of its oil and natural gas properties, it is difficult to predict with certainty the timing of drilling and completion of wells currently classified as PUD reserves. Historically, energy commodity prices have been volatile, and due to geopolitical risks in oil producing regions of the world as well as global supply and demand concerns, the Partnership continues to expect significant price volatility. Sustained lower prices for oil and natural gas may cause the Partnership in the future to forecast less capital to be available for development of its PUDs, which may cause the Partnership to decrease the number of PUDs it expects to develop within the five-year time frame. In addition, lower oil and natural gas prices may cause the Partnership’s PUDs to become uneconomic to develop, which would cause the Partnership to remove them from the proved undeveloped category.

 

Internal Controls Over Reserve Estimates and Qualifications of Technical Persons

 

The Partnership’s policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate its oil and gas reserves quantities and present values in compliance with rules, regulations and guidance provided by the SEC, as well as established industry practices used by independent engineering firms and the Partnership’s peers, and in accordance with the SPE 2007 Standards promulgated by the Society of Petroleum Engineers. The Partnership engaged Pinnacle Energy Services, LLC (“Pinnacle Energy”) to prepare the reserve estimates for all of the Partnership’s assets for the year ended December 31, 2018 in this annual report. Pinnacle Energy founder J.P. Dick has over 30 years of experience in the oil and natural gas industry, with exposure to reserves and reserve related valuations and issues during that time, and is a Registered Professional Engineer in the states of Texas and Oklahoma. Further qualifications include a bachelor of science in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, Mr. Dick is an active participant in industry reserve seminars, professional industry groups and is a member of the Society of Petroleum Engineers.

 

The Partnership’s controls over reserve estimates include engaging Pinnacle Energy as the Partnership’s independent petroleum engineer. The Partnership provided information about its oil and natural gas properties, including production profiles, prices and costs, to Pinnacle Energy and they prepared estimates of the Partnership’s reserves attributable to the Partnership’s properties. All of the information regarding reserves in this annual report on Form 10-K is derived from the report of Pinnacle Energy, which is included as an exhibit to this annual report on Form 10-K.

 

The Partnership’s General Partner works closely with Pinnacle Energy to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process as well as to review properties and discuss the methods and assumptions used by Pinnacle Energy in their preparation of the year-end reserve estimates. The Partnership’s General Partner also reviews the methods and assumptions used by Pinnacle Energy in the preparation of year-end reserve estimates, and assesses them for reasonableness. The Board of Directors of the General Partner also meets to discuss matters and policies related to the Partnership’s reserves.

 

The Partnership’s methodologies include reviews of production trends, analogy to comparable properties, and/or volumetric analysis. Performance methods are preferred. Reserve estimates for proved undeveloped properties are based primarily on volumetric analysis or analogy to offset production in the same or similar fields. The Partnership applies and maintains internal controls, including but not limited to the following, to ensure the reliability of reserves estimations:

 

 

no employee’s compensation is tied to the amount of reserves booked;

 

the Partnership follows comprehensive SEC-compliant internal policies to determine and report proved reserves;

 

reserve estimates are made by experienced reservoir engineers or under their direct supervision;

 

annual review by the Board of Directors of the General Partner of the Partnership’s year-end reserve estimates prepared by Pinnacle Energy; and

 

semi-annually, the Board of Directors of the General Partner reviews all significant reserves changes and all new proved undeveloped reserves additions.

 

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Total Productive Wells

 

The following table sets forth information with respect to the Partnership’s ownership interest in productive wells as of December 31, 2018:

 

   

December 31, 2018

 
   

Gross

   

Net

 

Oil wells:

               

Williston Basin, North Dakota

    261       15.4  

 

Of the total well count for 2018, none are multiple completions.

 

Productive wells are producing wells and wells the Partnership deems mechanically capable of production, including shut-in wells, wells waiting for completion, plus wells that are drilled/cased and completed, but waiting for pipeline hook-up. At December 31, 2018, the Partnership had 257 currently producing wells and four shut-in wells. A gross well is a well in which we own a working interest. The number of net wells represents the sum of fractional working interests the Partnership owns in gross wells.

 

Developed and Undeveloped Acreage Position

 

The following table sets forth information with respect to the Partnership’s gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2018, all of which is located in the State of North Dakota in the United States:

 

   

Acreage allocated to developed properties

   

Acreage allocated to undeveloped wellsites

   

Total Acres

 
   

Gross

   

Net

   

Gross

   

Net

   

Gross

   

Net

 

Williston Basin, North Dakota

    4,403       1,846       4,122       1,728       8,525       3,574  

 

As is customary in the oil and natural gas industry, the Partnership can generally retain an interest in undeveloped acreage through drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which the Partnership has an interest are for varying primary terms and, if production under a lease continues from developed lease acreage beyond the primary term, the Partnership is entitled to hold the lease for as long as oil or natural gas is produced. The oil and natural gas properties consist primarily of oil and natural gas wells and interests in developed leasehold acreage.

 

Undeveloped Acreage Expirations

 

The Partnership has no undeveloped acreage expirations as all acreage is held by production.

 

Delivery Commitments

 

As of December 31, 2018, the Partnership had no commitments to deliver a fixed quantity of oil or natural gas.

 

Marketing and Customers

 

The market for the Partnership’s oil and natural gas production depends on factors beyond its control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil and natural gas, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

 

The Partnership’s properties are operated by 14 third-party operators, who market and sell the Partnership’s production of oil, gas and natural gas liquids on behalf of the Partnership (and other fractional working interest owners).

 

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Title to Properties

 

As is customary in the Partnership’s industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time the Partnership acquires properties. The Partnership believes that its title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in the Partnership’s operations. The interests owned by the Partnership may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in the Partnership’s operations.

 

Insurance

 

Since the Partnership is not the operator of any of its properties, the Partnership relies on the insurance of the operator(s) of its properties, of which the Partnership’s share of the cost is allocated back to the Partnership through the Joint Operating Agreement. The Partnership’s operators have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to its oil and gas properties, control of well, auto liability, marine liability, worker’s compensation and employer’s liability, among other things.

 

The Partnership re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that the Partnership will be able to maintain insurance in the future at rates that the Partnership considers reasonable and the Partnership may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 

 

Competition

 

The oil and natural gas industry is highly competitive. The Partnership will encounter strong competition from independent oil and gas companies, master limited partnerships and from major oil and gas companies in acquiring properties, contracting for drilling equipment and arranging the services of trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than the Partnership’s. As a result, the Partnership’s competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than the Partnership’s financial or other resources will permit.

 

The Partnership also may be affected by competition for drilling rigs, human resources and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. The Partnership is unable to predict when, or if, such shortages may occur or how they would affect the Partnership’s development and exploitation program.

 

Seasonal Nature of Business

 

Seasonal weather conditions and lease stipulations can limit the Partnership’s drilling and producing activities and other operations in certain areas where the Partnership may acquire producing properties. These seasonal anomalies can pose challenges for meeting the Partnership’s drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increased costs or delay the Partnership’s operations. Generally, demand for natural gas is higher in summer and winter months. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter natural gas requirements during off–peak months. This can lessen seasonal demand fluctuations.

 

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Environmental, Health and Safety Matters and Regulation

 

The Partnership’s operations will be subject to stringent and complex federal, state and local laws and regulations that govern the oil and natural gas industry, as well as regulations that protect the environment from the discharge of materials into the environment. These laws and regulations may, among other things:

 

 

require the acquisition of various permits before drilling commences;

 

require the installation of pollution control equipment in connection with operations;

 

place restrictions or regulations upon the use or disposal of the material utilized in the Partnership’s operations;

 

restrict the types, quantities and concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

 

limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

 

require remedial measures to mitigate or remediate pollution from former and ongoing operations, and may also require site restoration, pit closure and plugging of abandoned wells; and

 

require the expenditure of significant amounts in connection with worker health and safety.

 

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on the Partnership’s operating costs. In general, the oil and natural gas industry has recently been the subject of increased legislation and regulatory attention with respect to environmental matters. The US Environmental Protection Agency, or EPA, has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2017 to 2019, although it is unclear about the outlook for this initiative with the current administration. Even if regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental regulation may continue for the long term.

 

The following is a summary of some of the existing laws, rules and regulations to which the Partnership’s business operations are subject.

 

Solid and Hazardous Waste Handling

 

The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous solid waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, the Partnership expects its operators to generate waste as a routine part of their operations that may be subject to RCRA. Although a substantial amount of the waste expected to be generated is regulated as non–hazardous solid waste rather than hazardous waste, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non–hazardous or exempt waste or categorize some non–hazardous or exempt waste as hazardous in the future. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than April 23, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Non-exempt waste is subject to more rigorous and costly disposal requirements. Any such change could result in substantial costs to manage and dispose of waste, which could have a material adverse effect on the Partnership’s results of operations and financial position.

 

Comprehensive Environmental Response, Compensation and Liability Act

 

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, imposes strict, joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so-called potentially responsible parties, or PRPs, include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

 

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Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of the Partnership’s operators’ expected operations, the operators will generate wastes that may fall within CERCLA’s definition of hazardous substance and may dispose of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum, and there is no guarantee that federal law will not adopt more stringent requirements with respect to the petroleum substances. The Partnership may also be the owner of sites on which hazardous substances have been released. If contamination is discovered at a site on which the Partnership is or has been an owner or to which the Partnership sent hazardous substances, the Partnership could be liable for the costs of investigation and remediation and natural resources damages. Further, the Partnership could be required to suspend or cease operations in contaminated areas.

 

The Partnership may own producing properties that have been used for oil and natural gas exploration and production for many years. Hazardous substances, wastes or hydrocarbons may have been released on or under the Partnership’s properties, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of the properties the Partnership has acquired may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under Partnership control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, the Partnership could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

 

Clean Water Act

 

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. Litigation surrounding this rule is ongoing. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non–compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, the Partnership may be liable for penalties and cleanup and response costs. The federal Clean Water Act only regulates surface waters. However most of the state analogs to the Clean Water Act also regulate discharges which impact groundwater.

 

In 2018, the EPA commenced an oil and gas extraction wastewater management study. The purpose of this study is to understand if support exists for new regulations that would allow for a broader discharge of oil and gas extraction wastewater directly to surface waters under the Clean Water Act’s National Pollutant Discharge Elimination System, in addition to the primary existing disposal methods of underground injection or discharge to centralized wastewater treatment facilities. The EPA intends to produce a white paper on the study in early 2019.

 

Safe Drinking Water Act and Hydraulic Fracturing

 

Many of the properties the Partnership owns will require additional drilling operations to fully develop the reserves attributable to the properties. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except for fracturing activities involving the use of diesel).

 

In prior sessions, Congress has considered legislation to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. This legislation has not passed. A number of states, local and regional regulatory authorities have or are considering hydraulic fracturing regulation and other regulations imposing new or more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations or restricting or banning hydraulic fracturing. Further, the EPA has issued an effluent limitations guideline prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned treatment plants.

 

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Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, there have been recent developments at the federal, state, regional and local levels that could result in regulation of hydraulic fracturing becoming more stringent and costly. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business.

 

If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where the Partnership owns properties that require additional drilling, the Partnership could incur substantial compliance costs and such requirements could adversely delay or restrict its ability to conduct fracturing activities on its assets. In December 2017, the Bureau of Land Management (“BLM”) rescinded its own rule from 2015 that would have required oil and gas companies to seek approval from BLM before conducting hydraulic fracturing operations on public lands and for companies to disclose the chemicals used in fracking fluid. However, the rescission of the rule is currently being challenged in federal court in California.

 

Toxic Substances Control Act and Hydraulic Fracturing

 

On August 4, 2011, Earthjustice and 114 other organizations petitioned the EPA under section 21 of the Toxic Substances Control Act (TSCA) to impose various requirements on E&P chemical substances and mixtures. In a letter dated November 2, 2011, the EPA informed petitioners that it denied the TSCA section 4 request and in a letter dated November 23, 2011, the EPA informed petitioners that it granted in part the TSCA petition and denied the TSCA petition in part. The EPA issued a notice seeking public comment on May 19, 2014; the comment period has not closed. This is part of the EPA’s general review of hydraulic fracturing.

 

Oil Pollution Act

 

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge on properties it owns, the Partnership may be liable for costs and damages.

 

Air Emissions

 

The operations of the Partnership’s operators are subject to the federal Clean Air Act, or CAA, and analogous state laws and local ordinances governing the control of emissions from sources of air pollution. The CAA and analogous state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (or toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or seek injunctive relief, requiring the Partnership to forego construction, modification or operation of certain air emission sources.

 

On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation. The EPA rules include standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards required owners/operators to reduce volatile organic compound, or VOC, emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of “green completions.” The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. The EPA has made and could continue to make revisions to clarify these rules in response to stakeholder comments. These rules and any revised rules may require the installation of equipment to control emissions on producing properties the Partnership owns.

 

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On June 3, 2016, the EPA expanded its regulatory coverage in the oil and gas industry with additional regulated equipment categories, and the addition of new rules limiting methane emissions from new or modified sites and equipment. The EPA attempted to suspend enforcement of the methane rule, but this action was challenged on appeal and was ruled improper. The EPA is reported to be considering rulemaking to rescind or revise the rule. In October 2018, the EPA issued a proposed rule to relax the new source performance standards that had instituted leak detection and repair requirements for methane from oil and gas sources. The proposal includes decreased frequency of well site monitoring, longer time periods for repairing leaks, and enhanced ability to satisfy federal requirements by complying with state fugitive emission requirements. The proposed rules have not yet been finalized.

 

In addition, in March 2018, the EPA proposed to withdraw “control technique guidelines” the EPA had previously issued to assist states in developing reasonably achievable control technology requirements for sources of volatile organic compounds. The Obama administration had originally issued these guidelines as part of its strategy to reduce methane emissions.

 

In November 2018, the EPA revised a previously stayed rule defining site aggregation for air permitting purposes. Under this rule, it is possible that some sites could require additional permitting under the Clean Air Act, an outcome that could result in costs and delays to the Partnership’s operations. However, this rule revival is being challenged in court.

 

On November 18, 2016, the BLM published a final rule, which became effective on January 17, 2017, that was intended to reduce waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on onshore Federal and Indian leases. Unlike the somewhat overlapping EPA regulations, which apply to new, modified and reconstructed sources, the BLM’s 2016 rule was drafted to address existing facilities, including a substantial number of existing wells that are likely to be marginal or low-producing, including leak detection and repair and other requirements regarding methane emissions. However, BLM issued a final rule in September 2018, that concluded that the costs the rule would impose would exceed the benefits it was expected to generate and therefore reduced certain compliance burdens deemed to be unnecessary, including requirements to write waste minimization plans, meet methane capture targets and use equipment that meets certain technical standards. BLM’s final rule is being challenged in court.

 

National Environmental Policy Act

 

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All proposed exploration and development plans on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

 

Climate Change Legislation

 

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause the Partnership to incur material expenses in complying with them. Both houses of Congress have considered legislation to reduce emissions of GHGs, but no legislation has yet passed. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. The EPA has adopted measures to reduce methane and other GHGs, as discussed above in “Air Emissions.”

 

In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries including onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities.

 

15

 

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and whether federal regulation of GHGs might take place. In addition to possible federal regulation, a number of states, individually and regionally as well as some localities, also are considering or have implemented GHG regulatory programs or other steps to reduce GHG emissions. These potential regional, state and local initiatives may result in so-called cap and trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in the Partnership incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from its operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas the Partnership produces. The impact of such future programs cannot be predicted, but the Partnership does not expect its operations to be affected any differently than other similarly situated domestic competitors.

 

Endangered Species Act

 

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The Partnership’s operators may conduct operations on oil and natural gas leases that have species that are listed and species that could be listed as threatened or endangered under the act. The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to use of the land and may materially delay or prohibit land access for oil and natural gas development. It also may adversely impact the value of the affected properties that the Partnership owns. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service was required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where the Partnership might conduct operations could result in limitations or prohibitions on its activities and could adversely impact the value of its leases.

 

In July 2018, the Fish and Wildlife Service proposed revisions to ESA regulations that somewhat loosen procedures for listing species, recovery, reclassifications and critical habitat designations. The proposal would remove the requirement that listing, delisting or reclassification of species be made “without reference to possible economic or other impacts of such determination.” The proposed rules could also further relax the protection afforded to species listed as “threatened” from those that are endangered, with the protection for “threatened” species being made on more of a case-by-case basis. The rules may be finalized by the middle of 2019.

 

OSHA and Other Laws and Regulation

 

The Partnership will be subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right–to–know regulations under the Title III of CERCLA and similar state statutes require that the Partnership organize and/or disclose information about hazardous materials used or produced in the Partnership’s operations.

 

Other Regulation of the Oil and Natural Gas Industry

 

The oil and natural gas industry is extensively regulated by numerous federal, state, local and tribal authorities. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential for financial sanctions for noncompliance. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the Partnership’s cost of doing business and, consequently, affects the Partnership’s profitability, these burdens generally do not affect the Partnership any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

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Drilling and Production

 

Statutes, rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted, making difficult the prediction of future costs or the impact of regulatory compliance attributable to new laws and statutes. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects its profitability. The drilling and production operations performed by the Partnership’s contracted operators will be subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which the Partnership operates also regulate one or more of the following:

 

●     the location of wells;

●     the method of drilling, completing and operating wells;

●     the surface use and restoration of properties upon which wells are drilled;

●     the plugging and abandoning of wells;

●     the marketing, transportation and reporting of production;

●     notice to surface owners and other third parties; and

●     produced water and waste disposal.

 

State and federal regulations are generally intended to prevent waste of oil and natural gas, protect correlative rights to produce oil and natural gas between owners in a common reservoir or formation, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and natural gas plants operated by other companies that provide midstream services to us are also subject to the jurisdiction of various federal, state and local authorities, which can affect the Partnership’s operations. State laws also regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties.

 

States generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within their respective jurisdictions. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

 

In addition, a number of states, such as North Dakota where the Partnership’s properties are located, and some tribal nations have enacted surface damage statutes, or SDAs. These laws are designed to compensate for damage caused by oil and natural gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and require specific payments by the operator to surface owners/users in connection with exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

 

The Partnership will not control the availability of transportation and processing facilities that may be used in the marketing of its production. For example, the Partnership may have to shut–in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

 

If the Partnership conducts operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by BLM, Bureau of Safety and Environmental Enforcement, Bureau of Indian Affairs, tribal or other appropriate federal, state and/or Indian tribal agencies.

 

The Mineral Leasing Act of 1920, or the Mineral Act, prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. The Partnership qualifies as an entity formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non–reciprocal countries, there are presently no such designations in effect. It is possible that the holders of the Partnership’s common units may be citizens of foreign countries and do not own their common units in a U.S. corporation or even if such interest is held through a U.S. corporation, their country of citizenship may be determined to be non–reciprocal countries under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by us could be subject to cancellation based on such determination.

 

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Federal Regulation of Oil, Natural Gas and Natural Gas Liquids, including Regulation of Transportation

 

The availability, terms and cost of transportation service significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). The intrastate transportation, local distribution and retail sale of natural gas generally are subject to state regulation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

 

FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under Section 311 of the Natural Gas Policy Act of 1978. FERC also authorizes the construction and operation of interstate natural gas pipelines under the Natural Gas Act (“NGA”).

 

Under FERC’s current regulatory regime, interstate natural gas transportation services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Among other things, the FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC.

 

With respect to its review of applications for the construction and operation of interstate natural gas pipeline facilities under the NGA, FERC must comply with environmental review requirements of NEPA.

 

Wellhead natural gas sale prices are unregulated. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices. The Partnership cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the properties the Partnership owns.

 

Sales of the Partnership’s oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act (“ICA”). The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. In 2017, FERC issued a declaratory holding that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the (higher) filed tariff rate, would violate the ICA. Rehearing of this order is pending before FERC.

 

Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.

 

The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk–based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet.

 

Transportation of the Partnership’s oil, natural gas liquids and purity components (ethane, propane, butane, iso–butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations, including Emergency Orders by the FRA. Revisions to PHMSA gathering line regulations and liquids pipelines regulations could result in the Partnership incurring significant expenses.

 

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Exports of US Oil Production and Natural Gas Production

 

At the end of 2015, the U.S. Congress voted to end a decades-old prohibition of exports of oil produced in the lower 48 states of the U.S. The U.S. Department of Energy (“DOE”) authorizes exports of U.S.-produced natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, which are expected to increase significantly with the changes taking place in the Mexican government’s regulations of the energy sector in Mexico. FERC authorizes the construction and operation of natural gas pipeline facilities crossing the U.S. border used to export U.S.-produced natural gas. In addition, the DOE authorizes the export of liquefied natural gas (“LNG”) through LNG export facilities, while FERC authorizes the siting and construction of onshore and near-short LNG export terminals. From 2012 through the end of 2018, DOE authorized large-scale, long-term (20 years) exports of U.S.-produced LNG totaling 23.05 billion cubic feet of natural gas to countries with which the U.S. has not entered into a free trade agreement providing for national treatment for trade in natural gas. The DOE has continued to authorize LNG exports into 2019.

 

Other Regulation

 

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. The Partnership does not believe that compliance with these laws will have a material adverse effect upon its operations.

 

Employees

 

The Partnership has no officers, directors or employees. Through the General Partner, the Partnership utilizes resources from Energy 11 to manage and administer the day-to-day affairs of the Partnership. All decisions regarding the management of the Partnership made by the General Partner will be made by the Board of Directors of the General Partner and its officers.

 

General Corporate Information

 

Energy Resources 12, L.P. is a Delaware limited partnership founded in 2016 with principal offices at 120 W 3rd Street, Suite 220, Fort Worth, Texas 76102. The Partnership can be reached at (817) 882-9192 and the Partnership website address is www.energyresources12.com. The Partnership makes available, free of charge through its Internet website, its annual report on Form 10-K and quarterly reports on Form 10-Q, and amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after the Partnership electronically files such material with, or furnishes it to, the SEC. Information contained on the Partnership’s website is not incorporated by reference into this report.

 

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Item 1A.  Risk Factors

 

Risks Related to an Investment in the Partnership

 

The chief executive officer and the chief financial officer have limited prior experience in investing in oil and gas properties.

 

The experience of the Partnership’s chief executive officer and chief financial officer is primarily in the real estate industry. This is the second oil and gas program in which the Partnership’s chief executive officer and chief financial officer have participated. You should consider an investment in the Partnership in light of the risks, uncertainties and difficulties frequently encountered by management operating in a new industry. The Partnership cannot guarantee that it will succeed in achieving its goals, and its failure to do so could cause you to lose all or a portion of your investment.

 

The Partnership has not engaged any personnel other than its chief executive officer and chief financial officer who have oil and gas experience.

 

The Partnership will rely on the General Partner (who currently only employs the chief executive officer and the chief financial officer) and independent oil and gas professionals to identify suitable investments. To the extent the General Partner relies on independent oil and gas professionals to provide these services, the Partnership may face competing demands on their time. Consequently, at times when the Partnership has capital ready for investment, it may experience delays in locating and evaluating suitable properties. The Partnership has agreed to share certain resources, including personnel, utilized by Energy 11 and engaged energy professionals as advisors to the Partnership to complete acquisitions on February 1, 2018 and August 31, 2018. Since these resources are shared or engaged on a part-time basis, these personnel may not have adequate time to devote to the Partnership. In the future, the General Partner may either hire additional personnel to support the acquisition and oversight processes for the Partnership or engage independent industry professionals as contractors to provide these services; however, there can no assurance that the Partnership will be able to hire or engage a sufficient number of qualified people to provide the required services.

 

The Partnership has limited prior operating history and limited established financing sources.

 

The Partnership, which was formed in 2016, has limited operating history. In addition, since its formation, the Partnership did not own or operate any oil and gas assets until February 2018. Companies that are, like the Partnership, in their early stage of development could experience increased operating and financing risks due to their limited operating history. The Partnership cannot guarantee that it will succeed in achieving its goals.

 

Distributions to the Partnership’s common unitholders may not be sourced from its cash generated from operations but from offering proceeds or indebtedness, and therefore the Partnership’s distributions during certain periods may exceed earnings and cash flows from operations, and this will decrease the Partnership’s distributions in the future; furthermore, the Partnership cannot guarantee that investors will receive any specific return on their investment.

 

The General Partner has the right to make distributions from the proceeds of borrowings and capital contributions. Offering proceeds that are returned to investors as part of distributions to them will not be available for investments in oil and gas properties. In addition, during certain periods, the Partnership expects that distributions may exceed the amount of earnings and cash flows from operations during such periods. The payment of distributions will decrease the cash available to invest in the Partnership’s oil and gas properties and will reduce the amount of distributions the Partnership may make in the future. The Partnership cannot and does not guarantee that investors will receive any specific return on their investment.

 

Moreover, as a result of entering into the Credit Facility in August 2018, the Partnership uses a portion of its cash flow to pay interest on and principal of this indebtedness when due, which will reduce the cash available to finance the Partnership’s operations and other business activities and could limit the Partnership’s flexibility in planning for or reacting to changes in the Partnership’s business and the industry in which it operates.

 

The Partnership depends on key personnel, the loss of any of whom could materially adversely affect future operations.

 

The Partnership’s success will depend to a large extent upon the efforts and abilities of Messrs. Knight and McKenney, the chief executive officer and chief financial officer. The loss of the services of one or more of these key employees could have a material adverse effect on the Partnership. The Partnership does not maintain key-man life insurance with respect to any employees. The Partnership’s business will also be dependent upon its ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause the Partnership to incur greater costs, or prevent it from pursuing its acquisition and development strategy as quickly as the Partnership would otherwise wish to do.

 

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The common units are not liquid and your ability to resell your common units will be limited by the absence of a public trading market and substantial transfer restrictions.

 

If you invest in the Partnership, then you must assume the risks of an illiquid investment. The common units generally will not be liquid because there is not a readily available market for the sale of common units, and one is not expected to develop. Further, although the Partnership Agreement contains provisions designed to permit the listing of common units on a national securities exchange, the Partnership does not currently intend to list the common units on any exchange or in the over-the-counter market.

 

If the General Partner elects to cause the Partnership to make distributions rather than reinvesting the cash flow in its business, the Partnership may be required to sell or farm-out properties or to elect not to participate in exploration or development drilling activities on its properties, which activities could turn out to be profitable.

 

If the Partnership were presented with an exploration or development drilling or other opportunity on its properties, and funding the opportunity would require the Partnership’s cash that is required in order to follow its distribution policy or for other purposes approved by the General Partner, the General Partner may elect to cause the Partnership to sell or farm-out the opportunity or decline to participate in the opportunity, even if the General Partner determines that the opportunity could have a favorable rate of return. The General Partner will have the right to cause the Partnership to participate in opportunities that will use the Partnership’s cash otherwise than in accordance with the distribution policy if the General Partner determines that pursuing such opportunity is in the best interests of the Partnership.

 

The General Partner will be subject to conflicts of interest in operating the Partnership, including conflicts of interest arising out of the General Partner’s ownership of the incentive distribution rights. The Partnership Agreement limits the General Partner’s fiduciary duties to the Partnership in connection with these conflicts of interest.

 

The General Partner will be subject to conflicts of interest in operating the Partnership’s business. These conflicts include:

 

conflicts caused by competition with other oil and gas partnerships that have been formed or may be formed by affiliates of the General Partner in the future, including competition for properties to be acquired;

conflicts caused by competition for the General Partner’s time and attention with other partnerships that the General Partner and its affiliates do and may sponsor and/or manage;

conflicts caused by the sale of properties to programs that have been or may be formed by the General Partner and its affiliates in the future;

conflicts caused by the incentive distribution rights which may cause the General Partner to conduct operations that are more risky to the Partnership, or to sell properties, in order to generate distributions from the incentive distribution rights; and

conflicts caused by the management fee the Partnership will pay to the General Partner since its compensation is a percentage of total gross equity proceeds raised in this offering.

 

The Partnership Agreement provides that the General Partner will have no liability to the Partnership or the holders of the common units for decisions made, if such decisions are made in good faith. In addition, the Partnership Agreement provides that if the General Partner receives a fairness opinion regarding the sale price of a property or in connection with a merger or the listing of the Partnership’s common units on a national securities exchange, including transactions that involve affiliates of the General Partner, the General Partner will be deemed to have acted in good faith.

 

There are conflicts of interest for the members of the General Partner because they are required to spend time on activities with other entities, and these other entities may compete with the Partnership in its business activity.

 

Messrs. Knight and McKenney, the chief executive officer and chief financial officer, respectively, will engage in unrelated business activities, either for their own account or on behalf of other partnerships, corporations or other entities in which they have an interest. Messrs. Knight and McKenney are also chief executive officer and chief financial officer, respectively, of Energy 11 GP, LLC, which manages working and other interests in oil and gas properties for Energy 11. This entity shares similar investment objectives and policies and may compete against the Partnership. Thus, the conflicts of interest experienced by management of the General Partner in allocating management time and efforts between the Partnership and Energy 11 GP, LLC may be particularly acute. Because management of the General Partner is required to spend time on other activities, there may be instances when they may not be able to assist the Partnership with certain matters and, as a result, the Partnership may be negatively impacted.

 

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Messrs. Knight and McKenney may form additional limited partnerships and other entities, and such companies may engage in activities similar to the Partnership. Companies organized by management of the General Partner in the future could have fees and other benefits payable to them (or to companies owned by them) which are more favorable than the fees and benefits payable by the Partnership to them (or to companies owned by them). The effect of this could be that management of the General Partner would spend more time on the activities of these other companies than on the Partnership’s activities, and/or prefer one or more of these companies to the Partnership with respect to actions such as the sale of properties.

 

The General Partner has sole responsibility for conducting the Partnership’s business and managing its operations. The General Partner and its affiliates will have conflicts of interest, which may permit them to favor their own interests to the detriment of holders of the Partnership’s common units.

 

Conflicts of interest may arise between the General Partner and its respective affiliates on the one hand, and the Partnership and the holders of its common units, on the other hand. In resolving these conflicts of interest, the General Partner may favor its own interests and the interests of its owners over the interests of holders of the Partnership’s common units. These conflicts include, among others, the following situations:

 

neither the Partnership Agreement nor any other agreement requires affiliates of the General Partner to pursue a business strategy that favors the Partnership or to refer any business opportunity to the Partnership;

the General Partner determines the amount and timing of its asset purchases and sales, capital expenditures and borrowings, each of which can affect the amount of cash that is distributed to holders of the Partnership’s common units or used to service its debt obligations;

the General Partner controls the enforcement of obligations owed to the Partnership by the General Partner and its affiliates; and

the General Partner decides whether to retain separate counsel, accountants or others to perform services for the Partnership.

 

Amounts paid to the General Partner, regardless of success of the Partnership’s activities, will reduce the cash the Partnership has available for distribution.

 

Subsequent to the Partnership’s first acquisition of the Bakken Assets on February 1, 2018, the General Partner and its affiliates receive an annual management fee, paid quarterly, of 0.5% of total gross equity proceeds raised in the Partnership’s offering. In addition, the General Partner and its affiliates have been or will be reimbursed for third-party costs incurred in connection with the formation of the Partnership and the Partnership’s business activities and have been or will be reimbursed for general and administrative costs of the general partner allocable to the Partnership regardless of the Partnership’s success in acquiring, developing and operating properties. The fees and direct costs to be paid to the General Partner will reduce the amount of cash distributions to investors. With respect to third-party costs, the General Partner has sole discretion on behalf of the Partnership to select the provider of the services or goods and the provider’s compensation.

 

Because the General Partner has discretion to determine the amount and timing of any distribution the Partnership may make, there is no guarantee that cash distributions will be paid by the Partnership in any amount or frequency even if its operations generate revenues.

 

The timing and amount of distributions will be determined in the sole discretion of the General Partner. The level of distributions, when made, will primarily be dependent upon the Partnership’s levels of revenue, among other factors. Distributions may be reduced or deferred, in the discretion of the General Partner, to the extent that the Partnership’s revenues are used or reserved for any of the following:

 

compensation and fees paid to the General Partner and its affiliates as described above in “— Amounts paid to the General Partner, regardless of success of the Partnership’s activities, will reduce cash distributions;”

the acquisition of primarily non-operated producing and non-producing oil and gas interests considered in the best interest of the Partnership by the General Partner;

repayment of borrowings;

drilling and completing new wells;

cost overruns on drilling, completion or operating activities;

remedial work to improve a well’s producing capability;

uninsured losses from operational risks including liability for environmental damages;

direct costs and general and administrative expenses of the Partnership;

reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or

indemnification of the General Partner and its affiliates by the Partnership for losses or liabilities incurred in connection with the Partnership’s activities.

 

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Further, because the Partnership’s investments will be in depleting assets, unless reinvested, Partnership revenues and the amount available for distribution to partners will decline with the passage of time. Accordingly, there can be no assurance that the Partnership will be able to make regular distributions or that distributions will be made at any consistent rate or frequency.

 

The Partnership may be unable to sell its properties, merge with another entity or list the common units on a national securities exchange within its planned timeline or at all.

 

Beginning five to seven years after the termination of the Partnership’s offering, the Partnership plans either to sell its properties and distribute the proceeds of the sale, after payment of liabilities and expenses, to its partners, merge with another entity, or list the common units on a national securities exchange. The decision to sell its properties will be based on a number of factors, including the demand for oil and natural gas assets in general, the price of oil, gas and other hydrocarbons which the Partnership’s properties produce, domestic and foreign supply of and demand for oil, natural gas and other hydrocarbons, the value of the Partnership’s assets, the projected amount of the Partnership’s oil and gas reserves, whether the planned development of the properties acquired has been finished by the operator, general economic conditions and other factors that are out of the Partnership’s control. The decision to sell the Partnership’s properties or merge with another entity will also be dependent upon any liabilities that the Partnership may be subject to, including contingent liabilities and conditions prevailing in the merger and acquisition market at the time. In addition, the ability to list its common units on a national securities exchange will depend on a number of factors, including the amount of assets, revenues and earnings that the Partnership has at the time of listing, the then existing market for oil and gas master limited partnerships, the state of the U.S. securities markets, the Partnership’s ability to meet the requirements of national securities exchanges, securities laws and regulations and other factors. If the Partnership is unable to either sell its properties, merge or list the common units on a national securities exchange in accordance with its current plans, you may be unable to sell or otherwise transfer your common units and you may lose some or all of your investment. While the Partnership plans to seek a liquidity event within five to seven years, the Partnership Agreement does not obligate the General Partner to cause a liquidity event within that timeline. The timing of a liquidity event will be dependent upon many factors, including prevailing market conditions, and the Partnership Agreement gives the Partnership flexibility on timing so that the Partnership is not forced to act during periods of low oil and gas prices, or other disadvantageous situations.

 

The ability to spread the risks of property acquisitions among a number of properties will be reduced if less than the maximum offering proceeds are received and fewer acquisitions are consummated.

 

The Partnership’s maximum offering proceeds may not exceed $350 million. There are no other requirements regarding the amount of offering proceeds to be received by the Partnership. Generally, the less offering proceeds received the fewer properties the Partnership would acquire, which would decrease the Partnership’s ability to spread the risks of acquisition and development of the Partnership’s properties.

 

The lack of geographical diversification may increase the risk of an investment in the Partnership.

 

All of the Partnership’s assets are located in concentrated areas of the Bakken shale in neighboring counties in North Dakota. While other companies and limited partnerships may have the ability to manage their risk by diversification, the narrow geographic focus of the Partnership’s business means that it may be impacted more acutely by factors affecting its industry or the region in which the Partnership operates than it would if its asset locations were more diversified. The Partnership may be disproportionately exposed to the effects of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of oil or natural gas. Additionally, the Partnership may be exposed to further risks, such as changes in field-wide rules and regulations that could cause the Partnership to permanently or temporarily shut-in all of its wells within the Williston Basin. The Partnership does not currently intend to broaden the geographic scope of its asset base.

 

In August 2018, the Partnership entered into a Credit Facility, and restrictions in the Credit Facility may limit the Partnership’s ability to make distributions to holders of its common units and may limit its ability to capitalize on acquisitions and other business opportunities.

 

The Partnership’s Credit Facility contains covenants limiting the Partnership’s ability to make distributions, incur indebtedness, grant liens, make acquisitions, make investments or dispositions and engage in transactions with affiliates, as well as covenants requiring the Partnership to maintain certain financial ratios and tests. In addition, the borrowing base under the Partnership’s Credit Facility is subject to periodic review by its lender. Difficulties in the credit markets may cause the banks to be more restrictive when redetermining the Partnership’s borrowing base. 

 

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The amount of indebtedness that the Partnership may incur is not limited by the terms of the Partnership Agreement.

 

The General Partner intends to limit the amount of borrowing to 50% of the Partnership’s total capitalization on an annual basis. However, the Partnership Agreement does not place any limitation on the amount of indebtedness that the General Partner may cause the Partnership to incur, and holders of common units will have no right to control or influence the amount of indebtedness the Partnership incurs. High levels of indebtedness may have adverse consequences for the Partnership, including:

 

Cash that would otherwise be available for distribution or to invest in the Partnership’s business will be used to pay interest on indebtedness;

Covenants in the indebtedness may restrict the Partnership’s ability to conduct its business, to make acquisitions or develop its assets and to make distributions; and

Default in the repayment of indebtedness could result in foreclosure on the Partnership’s assets, or require the Partnership to refinance indebtedness at higher costs.

 

The Partnership Agreement restricts the remedies available to holders of the Partnership’s common units for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duty.

 

The Partnership Agreement contains provisions that reduce or eliminate the fiduciary and other duties that the General Partner, its officers and the other persons who control it might have otherwise owed to the Partnership and the holders of the Partnership’s common units. In taking any action or making any decision on behalf of the General Partner or the Partnership, such persons will be presumed to have acted in good faith and, in any proceeding brought by or on behalf of any holder of common units or the Partnership, the person bringing such proceeding will have the burden of overcoming such presumption.

 

Furthermore, under the Partnership Agreement, the General Partner, its board of directors (and any committee thereof), its affiliates and the directors, officers and other persons who control the General Partner or any of its affiliates will not be liable for monetary damages to the Partnership or its limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such person acted in bad faith or engaged in fraud or willful misconduct, or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

 

Holders of the Partnership’s common units have limited voting rights and are not entitled to elect or remove the General Partner or the board of directors of the General Partner.

 

Unlike the holders of common stock in a corporation, common unitholders have only limited voting rights on matters affecting the Partnership’s business and, therefore, limited ability to influence management’s decisions regarding the Partnership’s business. Common unitholders will not elect the General Partner, or the members of its board of directors, and will have no right to remove the General Partner, or its board of directors. The Board of Directors of the General Partner is chosen by the owners of the General Partner.

 

Your liability may not be limited if a court finds that common unitholder action constitutes control of the Partnership’s business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. The Partnership is organized under Delaware law and it plans to conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which the Partnership may do business. You could be liable for any and all of the Partnership’s obligations as if you were a general partner if:

 

a court or government agency determined that the Partnership were conducting business in a state but had not complied with that particular state’s partnership statute; or

your right to act with other common unitholders to approve some amendments to the Partnership Agreement or to take other actions under the Partnership Agreement constitutes “control” of the Partnership’s business.

 

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Common unitholders may have liability to repay distributions that were wrongfully distributed to them.

 

Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17–607 of the Delaware Revised Uniform Limited Partnership Act, the Partnership may not make a distribution to you if the distribution would cause its liabilities to exceed the fair value of its assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to a partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the Partnership Agreement. Liabilities to partners on account of their partnership interest and liabilities that are non–recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

Fees and cost reimbursements that must be paid to the General Partner and the Managing Dealer regardless of success of the Partnership’s activities will reduce the cash the Partnership has available for distribution.

 

The General Partner and its affiliates have and will receive reimbursement of third-party costs incurred in connection with the formation of the Partnership and the Partnership’s business activities and have and will be reimbursed for general and administrative costs of the General Partner allocable to the Partnership, regardless of the Partnership’s success in acquiring, developing and operating properties. In addition, effective February 1, 2018, the General Partner receives an annual management fee, paid quarterly, of 0.5% of total gross equity proceeds raised in this offering. The Managing Dealer will receive sales commissions, marketing fees, the dealer manager incentive fees and account maintenance fees in connection with the offering. The fees and direct costs paid to the General Partner and the Managing Dealer reduce the amount of cash distributions to investors.

 

Common units may be purchased by individuals who have an interest in the offering different from yours.

 

The owners of the General Partner have each purchased 5,000 common units for $20.00 per unit. In addition, the Partnership Agreement does not restrict the ability of any service providers or vendors to the Partnership from purchasing common units. In addition, if a matter were to be submitted to a vote of holders of common units, the owners of the General Partner or other service providers or vendors who purchase common units may have different interests from other holders of common units in voting their common units.

 

Risks Related to the Partnership’s Business and the Oil and Natural Gas Industry

 

The Partnership may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements and management fees to the General Partner, to enable the Partnership to make cash distributions to holders of its common units under its cash distribution policy.

 

The Partnership may not have sufficient available cash each month to enable it to make cash distributions to the holders of common units. The amount of cash the Partnership can distribute on its common units principally depends upon the amount of cash the Partnership generates from its operations, which will fluctuate from month to month based on, among other things:

 

the amount of oil, natural gas and natural gas liquids the Partnership produces;

the prices at which the Partnership sells its production;

the Partnership’s ability to hedge commodity prices at economically attractive prices;

the level of the Partnership’s capital expenditures, including its costs to participate in wells;

the level of the Partnership’s operating and administrative costs including fees and reimbursement to the General Partner; and

the level of the Partnership’s interest expense, which depends on the amount of its indebtedness and the interest payable thereon.

 

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In addition, the actual amount of cash the Partnership will have available for distribution will depend on other factors, some of which are beyond the Partnership’s control, including:

 

the amount of cash reserves established by the General Partner for the proper conduct of the Partnership’s business and for capital expenditures, which may be substantial;

the operator(s) of the Partnership’s properties will control the timing of any capital expenditures necessary to drill or overhaul any wells on the properties the Partnership invests in;

the cost of operations, infrastructure and drilling;

the Partnership’s debt service requirements and other liabilities;

fluctuations in the Partnership’s working capital needs;

the Partnership’s ability to borrow funds;

the timing and collectability of receivables; and

prevailing economic conditions.

 

As a result of these factors, the amount of cash the Partnership distributes to holders of its common units may fluctuate significantly from month to month.

 

If oil, natural gas or other hydrocarbon prices decrease and remain depressed for a prolonged period, cash flows from operations will decline and the Partnership may have to lower its distributions or may not be able to pay distributions at all.

 

The Partnership’s revenue, profitability and cash flow depend upon the prices for oil, natural gas and other hydrocarbons. The prices the Partnership receives for its production will be volatile and a drop in prices can significantly affect its financial results and adversely affect the Partnership’s ability to obtain credit, maintain its borrowing capacity and to repay indebtedness, all of which can affect the Partnership’s ability to pay distributions. Changes in prices have a significant impact on the value of the Partnership’s reserves and on its cash flows. Prices may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond the Partnership’s control, such as:

 

the domestic and foreign supply of and demand for oil and natural gas and other hydrocarbons;

the price and quantity of foreign imports of oil and natural gas and other hydrocarbons;

recent changes in federal regulations removing decades-old prohibition of the export of crude oil production in the U.S.;

federal regulations applicable to exports of liquefied natural gas (“LNG”), including the commencement in 2016 of exports of LNG liquefied from natural gas produced in the lower 48 states of the U.S.;

the level of consumer product demand;

weather conditions and natural disasters;

domestic and foreign governmental regulations, including environmental initiatives and taxation;

overall domestic and global economic conditions;

the value of the U.S. dollar relative to the currencies of other countries;

political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

the proximity and capacity of natural gas pipelines and other transportation facilities to the Partnership’s production;

technological advances affecting energy consumption;

the price and availability of alternative fuels; and

the impact of energy conservation efforts.

 

Decreased oil, natural gas and other hydrocarbon prices will decrease Partnership revenues, and may also reduce the amount of oil, natural gas or other hydrocarbons that the Partnership can economically produce. If decreases occur, or if estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require the Partnership to write down, as a non–cash charge to earnings, the carrying value of its oil and natural gas properties for impairments. The Partnership is required to perform impairment tests on its assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. The Partnership may incur impairment charges in the future, which could have a material adverse effect on its results of operations in the period taken and the Partnership’s ability to borrow funds under a credit facility, which may adversely affect the Partnership’s ability to make cash distributions to holders of its common units and service its debt obligations.

 

26

 

The Partnership will need additional funding in order to retain its full interest in the Bakken Assets.

 

In addition to the $170 million combined purchase price for Acquisitions No. 1 and No. 2 and approximately $15 million of capital expenditures incurred to drill additional wells in 2018, the Partnership anticipates that it may be obligated to invest an additional $115 to $125 million in drilling and well completion capital expenditures through 2023 to fully participate in operator drilling programs in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements governing those properties. The Partnership will depend, at least in part, on continued sales pursuant to the terms of its ongoing public offering, increased cash flow from operations and may require refinancing of its existing debt and/or additional financing to repay existing debt and to fund the anticipated capital expenditures needed to retain its full interest in the Bakken Assets. None of these funding sources is guaranteed, and if the Partnership is unable to obtain all of this funding, the Partnership may lose all or a portion of the assets acquired or reduce distributions, and its results of operations will be negatively affected accordingly.
 

The Partnership has limited control over the activities on its properties.

 

Fourteen other companies operate the properties the Partnership has acquired. The Partnership will have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that it is required to fund. The failure of an operator of the Partnership’s wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in the Partnership’s best interest could reduce the Partnership’s production and revenues. The Partnership’s dependence on the operator and other working interest owners for these projects and its limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of the Partnership’s targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

 

The Partnership participates in oil and gas leases with third parties who may not be able to fulfill their commitments to the Partnership’s projects.

 

The Partnership owns less than 100% of the working interest in the Bakken Assets, and other parties own the remaining portion of the working interests. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. The Partnership could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. Another working interest owner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy. In the event any of the Partnership’s co-owners do not pay their share of such costs, the Partnership would likely have to pay its share of those costs, and the Partnership may be unsuccessful in any efforts to recover these costs from its partners, which could materially adversely affect the Partnership’s financial position.

 

Because the Partnership will depend on the General Partner and its affiliates to conduct the Partnership’s operations, any adverse changes in the financial health of the General Partner could hinder the Partnership’s operating performance and ability to make distributions.

 

The Partnership will depend on the General Partner and its affiliates and other third-party operators for the development and operation of the Partnership’s properties. The General Partner has limited operating history. Any adverse changes in the financial condition of the General Partner or in the Partnership’s relationship with the General Partner or its officers and employees could hinder its or their ability to successfully manage the Partnership’s operations.

 

Any adverse changes in the financial health of Energy 11 could hinder the Partnership’s operating performance and ability to make distributions.

 

The Partnership and Energy 11 signed a cost sharing agreement in January 2018 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 Partnership and Energy 11 evenly split these shared costs. If the financial health of Energy 11 deteriorates or if Energy 11 has a liquidating event and ceases its operations, the Partnership would be solely responsible for all expenses under the cost sharing agreement, which may reduce the Partnership’s operating results and its ability to make distributions to common unitholders. In addition, Energy 11 resources may not be available to the Partnership, and the Partnership would have to find and engage resources to manage its day-to-day operations.

 

27

 

Property interests that the Partnership has purchased or of which the Partnership participates in the development may not produce as projected and the Partnership may be unable to realize reserve potential, which could adversely affect the Partnership’s cash available for distribution.

 

The Partnership’s completed acquisitions and any decision to participate in the development of a property the Partnership owns required or will require an assessment of recoverable reserves, title, future oil, natural gas and natural gas liquids prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and similar factors. Reserve estimates may be prepared by the operators or third parties for the operators of properties. The Partnership has engaged and may engage its own third-party petroleum engineers to review such reserve estimate reports and provide the Partnership with an independent assessment of the reserve estimates. The process of estimating oil and gas reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors such as future oil and gas prices, drilling and operating expenses, capital expenditures, taxes and the availability of funds, all of which can be difficult to predict with accuracy. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact the Partnership’s financial conditions and results of operations and its ability to make cash distributions to holders of its common units and service its debt obligations.

 

Additional potential risks at the acquisition date and those related to development include, among other things:

 

incorrect assumptions regarding the future prices of oil, natural gas and other hydrocarbons or the future operating or development costs of properties acquired;

incorrect estimates of the reserves and projected development results attributable to a property the Partnership acquires;

drilling, operating and other cost overruns by the operator of the properties;

an inability to integrate successfully the properties the Partnership acquires;

the assumption of liabilities;

the diversion of management’s attention from other business concerns; and

losses of key employees.

 

The operators of the Partnership’s properties may engage in exploration activities on these properties which activities are more risky than development activities.

 

The Partnership has acquired interests in oil and gas properties which require additional drilling and other exploration activities to fully develop. Some of the drilling on its properties may be classified as exploration drilling. Exploration drilling is inherently more risky than development drilling. Although the Partnership expects that any exploration drilling will generally be located near areas which have undergone successful drilling or in areas with geological characteristics similar to areas which have been successfully developed, no assurances can be made that the exploration or development drilling will be successful in discovering producible oil and gas reserves.

 

The General Partner may cause the Partnership not to participate with the operator in the drilling of wells on the Partnership’s properties.

 

If the Partnership has the opportunity to participate in wells, the General Partner may decide to sell or farmout the well. Also, if a well is proposed under an operating agreement for one of the properties the Partnership owns, the General Partner may cause the Partnership to “non-consent” the well under the applicable operating agreement. 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. If the General Partner makes the decision to sell, farmout or non-consent a well or other development activity, the Partnership Agreement provides that the General Partner will have no liability to the Partnership so long as the decision is made in good faith.

 

28

 

The Partnership could experience periods of higher costs if oil and natural gas prices rise or as drilling activity otherwise increases in the Partnership’s area of operations. Higher costs could reduce the Partnership’s profitability and cash flow.

 

Historically, capital and operating costs typically rise during periods of sustained increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond the Partnership’s control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that the Partnership and its vendors will rely upon, and the cost of services and labor especially those required in horizontal drilling and completion. Historically, oil and natural gas prices have fluctuated resulting in fluctuating levels of drilling activity in the U.S. oil and natural gas industry. Lower prices typically lead to lower costs of some drilling and completion equipment, services, materials and supplies. As commodity prices rise or stabilize or drilling activity otherwise increases, these lower cost levels may not be sustainable over long periods. As a result, such costs may rise faster than selling prices thereby negatively impacting the Partnership’s profitability, cash flow and causing it to possibly reconfigure or reduce its drilling program.

 

Federal and state legislative initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays, and even could result in the Partnership ceasing business operations.

 

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from dense rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The operators of the properties the Partnership acquires will routinely use hydraulic fracturing techniques in most drilling and completion programs. In past legislative sessions, legislation was introduced before Congress to provide for federal regulation of hydraulic fracturing using materials other than diesel under the Safe Drinking Water Act and to require disclosure of the chemicals used in the fracturing process; this legislation has not passed. At the state and local levels, some jurisdictions have adopted, and others are considering adopting, requirements that could impose more stringent permitting, public disclosure of fracturing chemicals or well construction requirements on hydraulic fracturing activities, as well as bans on hydraulic fracturing activities. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Partnership acquires producing properties, the Partnership could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from participating in drilling wells. More widespread or prolonged moratoriums or prohibitions of hydraulic fracturing could, depending on the makeup of the Partnership’s assets, cause the Partnership to cease business operations.

 

The Environmental Protection Agency’s (“EPA”) enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing, impact the Partnership’s ability to conduct business, and increase the Partnership’s costs of compliance and doing business.

 

Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. The EPA has announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. The EPA also issued a pretreatment standard for the discharge of wastewater resulting from hydraulic fracturing activities, prohibiting the discharges of wastewater pollutants from onshore unconventional oil and gas extraction to publicly owned treatment works. The EPA has released a draft of a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. In December 2016, the EPA released its final report “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” This report concludes that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain data gaps and uncertainties limited the EPA’s assessment. The EPA has identified environmental compliance by the energy extraction sector to be one of its enforcement initiatives for 2017 to 2019, although it is unclear about the outlook for this initiative with the current administration. Even if regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental regulation may continue for the long term. Any additional regulatory actions taken by the EPA could increase the costs of the Partnership’s operations or result in additional operating restrictions or delays. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that the Partnership ultimately is able to produce.

 

29

 

The Partnership’s hedging transactions will expose it to counterparty credit risk.

 

In 2018, the Partnership engaged in hedging transactions to reduce, but not eliminate, the effect of volatility in oil, gas and other hydrocarbon prices, as required by the Credit Facility. The Partnership’s hedging transactions expose the Partnership to risk of financial loss if a counterparty fails to perform under a derivative contract. The risk of counterparty non-performance is of particular concern when there are disruptions in the financial markets and there are significant declines in oil and natural gas prices. Either of these events could lead to sudden changes in a counterparty’s liquidity and impair its ability to perform under the terms of the derivative contract. The Partnership is unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if the Partnership does accurately predict sudden changes, the Partnership’s ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of the Partnership’s hedge providers or some other similar proceeding or liquidity constraint might make it unlikely that the Partnership would be able to collect all or a significant portion of amounts owed to it by the distressed entity or entities.

 

During periods of falling commodity prices the Partnership’s hedge receivable positions increase, which increases the Partnership’s exposure. If the creditworthiness of the Partnership’s counterparties deteriorates and results in their nonperformance, the Partnership could incur a significant loss.

 

The Partnership’s hedging activities could result in financial losses or could reduce the Partnership’s net income, which may adversely affect the Partnership’s ability to pay cash distributions to holders of its common units.

 

To achieve more predictable cash flows and to reduce the Partnership’s exposure to fluctuations in the prices of oil, natural gas and other hydrocarbons, the Partnership has and may enter into hedging arrangements for a significant portion of its estimated future production. If the Partnership experiences a sustained material interruption in its production, the Partnership might be forced to satisfy all or a portion of its hedging obligations without the benefit of the cash flows from the Partnership’s sale of the underlying physical commodity, resulting in a substantial diminution of its liquidity.

 

The Partnership’s ability to use hedging transactions to protect it from future price declines will be dependent upon oil and natural gas prices at the time the Partnership enters into future hedging transactions and the Partnership’s future levels of hedging, and as a result its future net cash flows may be more sensitive to commodity price changes. Additionally, it may not be possible or economic to hedge all of the hydrocarbons the Partnership produces because of the lack of a market for such hedges or other reasons. The Partnership may hedge certain hydrocarbons it produces by entering into swaps, collars or other contracts covering hydrocarbons the Partnership considers to be priced similarly to the hydrocarbons it produces, and could be subject to losses if the prices for the hydrocarbons the Partnership produces do not match the hydrocarbons the Partnership contracts for.

 

In conjunction with the hedging requirements of the Credit Facility, the Partnership is required to hedge 50% of its estimated production through the Credit Facility maturity date of August 31, 2021. The prices at which the Partnership hedges its production are and will be dependent upon commodity prices at the time the Partnership enters into these transactions, which may be substantially higher or lower than current oil, natural gas and other hydrocarbon prices. Accordingly, the Partnership’s hedges may not fully protect it from significant declines in oil and natural gas prices received for its future production. Conversely, the Partnership’s hedges may limit its ability to realize cash flows from commodity price increases. The General Partner will not be liable for any losses the Partnership incurs as a result of the Partnership’s hedge transactions.

 

The adoption of derivatives legislation and regulations related to derivative contracts could have an adverse impact on the Partnership’s ability to hedge risks associated with its business.

 

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts the Partnership uses to hedge its exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.

 

30

 

In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on November 7, 2013, a proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. On May 27, 2016, the CFTC issued a proposed supplement to its 2013 position limits proposal, which is intended to modify the process by which a non-enumerated hedging transaction may be determined to be a “bona fide hedge” transaction, and thereby become exempt from the CFTC’s position limits. A final rule has not yet been issued. Similarly, the CFTC has issued a proposed rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.

 

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear all swap transactions through a derivatives clearing organization and to trade all such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

 

All of the above regulations could increase the costs to the Partnership of entering into financial derivative transactions to hedge or mitigate its exposure to commodity price volatility and other commercial risks affecting its business. While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on the Partnership’s ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate its commercial risks, these rules and regulations may require the Partnership to comply with position limits and with certain clearing and trade-execution requirements in connection with the Partnership’s financial derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require the Partnership’s current swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with the Partnership, which capital requirements rule could increase the costs to the Partnership of future financial derivatives transactions. The Volcker Rule provisions of the Dodd-Frank Act may also require the Partnership’s current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like the Partnership, as commercial end-users, to have access to financial derivatives to hedge or mitigate the Partnership’s exposure to commodity price volatility.

 

As a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect the Partnership’s capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of the Partnership’s existing bilaterally negotiated financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks the Partnership encounters.

 

If the Partnership reduces its use of derivative contracts as a result of the new requirements, the Partnership’s results of operations may become more volatile and cash flows less predictable, which could adversely affect its ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. The Partnership’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Partnership’s financial condition, results of operations, or cash flows.

 

The financial conditions of any hydrocarbon purchasers the Partnership does business with could have an adverse impact on us in the event these purchasers are unable to pay for the Partnership’s share of oil and gas production.

 

Some of the Partnership’s hydrocarbon purchasers may experience severe financial problems that may have a significant impact on their creditworthiness. The Partnership cannot provide assurance that one or more of its hydrocarbon purchasers will not default on their obligations to the Partnership or that such a default or defaults will not have a material adverse effect on the Partnership’s business, financial position, future results of operations or future cash flows. Furthermore, the bankruptcy of one or more of the Partnership’s hydrocarbon purchasers, or some other similar proceeding or liquidity constraint, might make it unlikely that the Partnership would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such purchasers to reduce or curtail their future purchase of the Partnership’s production and services, which could have a material adverse effect on the Partnership’s results of operations and financial condition.

 

31

 

The Partnership plans to rely on drilling to fully develop their potential. If drilling and well completion are unsuccessful, the Partnership’s cash available for distributions and financial condition will be adversely affected.

 

The Partnership has acquired oil and gas properties that are not fully developed, and require that the Partnership engages in drilling and well completion to fully exploit the reserves attributable to the properties. Because the Partnership has acquired non-operated properties, it will not be in charge of the drilling and well completions, but will be obligated to pay its pro rata share of drilling and completion costs or be subject to penalties. Drilling will involve numerous risks, including the risk that the Partnership will not encounter commercially productive oil or natural gas reservoirs. The Partnership may incur significant expenditures to drill and complete wells, including cost overruns. Additionally, current geoscience technology may not allow the Partnership to know conclusively, prior to drilling a well, that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and it is possible that the Partnership will make substantial expenditures on drilling and not discover reserves in commercially viable quantities. These expenditures will reduce cash available for distribution to holders of the Partnership’s common units and for servicing the Partnership’s debt obligations.

 

The Partnership’s drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

 

unexpected drilling or operating conditions;

facility or equipment failure or accidents;

shortages or delays in the availability of drilling rigs and equipment and in hiring qualified personnel;

adverse weather conditions;

shortages of water required for hydraulic fracturing or other operations;

compliance with environmental and governmental requirements;

reductions in oil or gas prices;

proximity to and capacity of transportation and processing facilities;

title problems;

encountering abnormal pressures or unusual, unexpected or irregular geological formations;

pipeline ruptures;

fires, blowouts, craterings and explosions; and

uncontrollable flows of oil or natural gas or well fluids.

 

Even if drilled, completed wells may not produce quantities of oil or natural gas that are economically viable or that meet earlier estimates of economically recoverable reserves. A productive well may become uneconomic if water or other deleterious substances are encountered, which impair or prevent the production of oil and/or natural gas from the well. Overall drilling success rates or drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in the Partnership’s production and revenues and materially harm the Partnership’s operations and financial condition by reducing its available cash and resources.

 

The Partnership’s continued success depends upon its ability to develop oil and gas reserves that are economically recoverable.

 

In addition, the Partnership’s future oil and natural gas production will depend on its success in developing its assets to add to its reserves. If the Partnership is unable to replace reserves through drilling, the Partnership’s level of production and cash flows will be adversely affected. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. The Partnership’s total proved reserves decline as reserves are produced unless the Partnership conducts other successful acquisition and development activities. The Partnership’s ability to make the necessary capital investment to maintain or expand its asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. The Partnership may not be successful in developing its assets to increase its reserves.

 

32

 

The Partnership may be unable to compete effectively with larger companies, which may adversely affect its ability to generate sufficient revenue and its ability to pay distributions to holders of its common units and service its debt obligations.

 

The oil and natural gas industry is intensely competitive, and the Partnership competes with other companies that have greater resources than the Partnership. Many of the Partnership’s larger competitors not only acquire properties, drill for and produce oil and natural gas, but also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue drilling activities during periods of low commodity prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. The Partnership’s inability to compete effectively with larger companies could have a material adverse impact on its business activities, financial condition and results of operations.

 

The Partnership’s business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect the Partnership’s financial condition or results of operations and, as a result, the Partnership’s ability to pay distributions to holders of its common units and service its debt obligations.

 

The Partnership’s business activities are subject to operational risks, including:

 

damages to equipment caused by natural disasters such as earthquakes, adverse weather conditions, including tornadoes, hurricanes, drought and flooding;

unexpected formations and pressures;

facility or equipment malfunctions;

pipeline ruptures or spills;

fires, blowouts, craterings and explosions;

release of toxic gasses;

uncontrollable flows of oil or natural gas or well fluids; and

surface fluid spills, saltwater contamination, and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives.

 

Any of these events could adversely affect the Partnership’s ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension cessation or of operations, and attorneys’ fees and other expenses incurred in the prosecution or defense of litigation and could also result in requirements to remediate, regulatory investigations, and/or the interruption of the Partnership’s business and/or the business of third parties.

 

As is customary in the industry, the operator of the properties will maintain insurance against some but not all of these risks. The Partnership may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on the Partnership’s business activities, financial condition, results of operations and ability to pay distributions to holders of its common units and service its debt obligations.

 

33

 

The Partnership’s financial condition and results of operations may be materially adversely affected if the Partnership incurs costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

 

The Partnership may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of its wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

 

the Clean Air Act, or the CAA, and comparable state laws and regulations that impose obligations related to emissions of air pollutants;

the Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated water;

the Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from oil and gas facilities;

the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned by us or at locations to which the Partnership has sent waste for disposal;

the Safe Drinking Water Act and state or local laws and regulations related to underground injection (including hydraulic fracturing);

the Endangered Species Act and comparable state and local laws and regulations which protect endangered and threatened species and the ecosystems on which they depend;

the National Environmental Policy Act and comparable state statutes which ensure that environmental issues are adequately addressed in decisions involving major governmental actions (including the leasing of government land);

the Toxic Substances Control Act and comparable state statutes which regulate the manufacture, use, distribution and disposal of chemical substances;

the Oil Pollution Act, or OPA, which subjects responsible parties to liability for removal costs and damages arising from an oil spill in waters of the U.S.; and

emergency planning and community right to know regulations under the Title III of CERCLA and similar state statutes require that the Partnership organizes and/or discloses information about hazardous materials used or produced in the Partnership’s operations.

 

Under these laws and regulations, the Partnership could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties and the issuance of orders enjoining future operations. Certain environmental statutes, including CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations, including any related to climate change and greenhouse gases, may be adopted in the future. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

 

The Partnership is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting the Partnership’s operations.

 

The Partnership’s business is subject to complex and stringent laws and regulations governing the acquisition, development, operation, production and marketing of oil and gas, taxation, safety matters and the discharge of materials into the environment. In order to conduct the Partnership’s operations in compliance with these laws and regulations, the operator(s) of the Partnership’s properties must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining and maintaining regulatory approvals or drilling permits could have a material adverse effect on the Partnership’s ability to develop its properties, and receipt of drilling permits with onerous conditions could increase the Partnership’s compliance costs. In addition, regulations regarding resource conservation practices and the protection of correlative rights affect the Partnership’s operations by limiting the quantity of oil, natural gas and natural gas liquids the Partnership may produce and sell.

 

34

 

The Partnership is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil, natural gas and natural gas liquids. While the cost of compliance with these laws is not expected to be material to the Partnership’s operations, the possibility exist that new laws, regulations or enforcement policies could be more stringent and significantly increase the Partnership’s compliance costs. If the Partnership is not able to recover the resulting costs through insurance or increased revenues, the Partnership’s ability to pay distributions to holders of the Partnership’s common units and service the Partnership’s debt obligations could be adversely affected.

 

Climate change legislation or regulations restricting emissions of greenhouse gases, or GHGs, could result in increased operating costs and reduced demand for the oil, natural gas and natural gas liquids the Partnership produces.

 

In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. These permitting provisions, to the extent applicable to our operations, could require the operator(s) of the Partnership’s properties to implement emission controls or other measures to reduce GHG emissions and the Partnership could incur additional costs to satisfy those requirements. Further, the EPA has adopted rules to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing and transmission sources, and has announced its intention to regulate methane emissions from existing oil and gas sources. Although some of these requirements may ease under the current administration, the broader recent trend of more expansive and stricter climate change regulation may continue for the long term.

 

In addition, the EPA requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities the Partnership owns. Reporting of GHG emissions from such facilities is required on an annual basis. Should the operator(s) of the Partnership’s properties trigger the reporting requirement, the Partnership will incur costs associated with the reporting obligation.

 

In past legislative sessions, Congress considered legislation to reduce emissions of GHGs and many states and regions have adopted or have considered measures to reduce GHG emission reduction levels, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. Federal efforts at a cap and trade program have not moved forward in Congress. The adoption and implementation of any legislation or regulatory programs imposing reporting obligations on, or limiting emissions of GHGs from, equipment and operations on the Partnership’s properties could require the Partnership to incur costs to reduce emissions of GHGs associated with the Partnership’s operations or could adversely affect demand for the oil, natural gas and natural gas liquids that the Partnership produces.

 

Significant physical effects of climatic change have the potential to damage the Partnership’s facilities, disrupt the Partnership’s production activities and cause the Partnership to incur significant costs in preparing for or responding to those effects.

 

In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, the operations that the Partnership plans to engage in may be adversely affected. Potential adverse effects could include damages to the Partnership’s facilities from powerful winds or rising waters in low lying areas, disruption of the Partnership’s production activities either because of climate-related damages to the Partnership’s facilities or the Partnership’s costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on the Partnership’s financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom the Partnership has a business relationship. The Partnership may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. Should drought conditions occur, the Partnership’s ability to obtain water in sufficient quality and quantity could be impacted and in turn, the Partnership’s ability to perform hydraulic fracturing operations could be restricted or made more costly. 

 

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The Partnership expects to be subject to regulation under New Source Performance Standards, or NSPS, and National Emissions Standards for Hazardous Air Pollutants, or NESHAP programs, which could result in increased operating costs.

 

On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and the NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards required owners/operators to reduce volatile organic compound, or VOC, emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also established specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. The EPA has issued new rules limiting methane emissions from new or modified oil and gas sources. The rules amend the air emissions rules for the oil and natural gas sources and natural gas processing and transmission sources to include new standards for methane. The EPA attempted to suspend enforcement of the methane rule, but this action as challenged on appear and was ruled improper. The EPA is reported to be considering rulemaking to rescind or revise the rule. Simultaneously with the methane rules, the EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality permitting purposes. In addition, the EPA had announced plans to begin work on regulations to regulate methane emissions from existing oil and gas sources. These rules and any revised rules may require the installation of equipment to control emissions on the Partnership’s producing properties or could require the Partnership to obtain permits for such operations. Although some of these requirements may ease under the current administration, the broader recent trend of more expansive and stricter climate change regulation may continue for the long term.

 

The Partnership and the operators of its properties may encounter obstacles to marketing the Partnership’s share of oil, natural gas and other hydrocarbons, which could adversely impact the Partnership’s revenues.

 

The marketability of the Partnership’s production will depend upon numerous factors beyond the Partnership’s control, including the availability and capacity of natural gas gathering systems, pipelines and other transportation and processing facilities that the Partnership expects to be owned by third parties. Transportation space on the gathering systems and pipelines the Partnership expects to utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. The Partnership’s access to transportation and processing options and the marketing of the Partnership’s production can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, as well as the other risks discussed above. The availability of markets is beyond the Partnership’s control. If market factors dramatically change, the impact on the Partnership’s revenues could be substantial and could adversely affect the Partnership’s ability to produce and market oil, natural gas and natural gas liquids, the value of the Partnership’s common units and the Partnership’s ability to pay distributions on the Partnership’s common units and service the Partnership’s debt obligations.

 

The Partnership may be required to shut-in wells or delay initial production for lack of a viable market or because of the inadequacy or unavailability of pipeline, gathering system, processing, treating, fractionation or refining capacity. When that occurs, the Partnership will be unable to realize revenue from such wells until the inadequacy or unavailability is remedied. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

 

Legislation or regulatory initiatives intended to address seismic activity could restrict the Partnership’s ability to dispose of saltwater gathered from the Partnership’s drilling and production activities, which could have a material adverse effect on the Partnership’s business.

 

The properties that the Partnership has already or may acquire may require the Partnership to dispose of saltwater gathered from its operations pursuant to permits issued to the Partnership by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent permitting or operating constraints or new monitoring and reporting requirements owing to, among other things, concerns of the public or governmental authorities regarding such disposal activities.

 

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One such concern relates to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and natural gas activities. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. The United States Geological Survey also noted the potential for induced seismicity in Ohio and Alabama. In response to these concerns, regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for wastewater disposal wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations.

 

Also, ongoing lawsuits allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells. Increased regulation and attention given to induced seismicity could lead to greater opposition, including litigation, to oil and gas activities utilizing injection wells for waste disposal. Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of saltwater into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where saltwater disposal activities occur or are proposed to be performed. Court decisions or the adoption of any new laws, regulations, or directives that restrict the Partnership’s ability to dispose of saltwater generated by production and development activities, whether by plugging back the depths of disposal wells, reducing the volume of saltwater disposed in such wells, restricting disposal well locations or otherwise, or by requiring the Partnership to shut down disposal wells, could significantly increase the Partnership’s costs to manage and dispose of this saltwater, which could have a material adverse effect on the Partnership’s financial condition and results of operations.

 

There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm the Partnership’s business may occur and not be detected.

 

The Partnership’s management, including the chief executive officer and chief financial officer, do not expect that the Partnership’s or the Partnership’s operators’ internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in the Partnership have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of the Partnership’s controls and procedures to detect error or fraud could seriously harm the Partnership’s business and results of operations.

 

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact the Partnership’s operations.

 

The Partnership’s business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. The Partnership depends on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with the general partner and third-party partners. Unauthorized access to the Partnership’s seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in the Partnership’s exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport the Partnership’s production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

 

While the Partnership has not experienced cyber-attacks, there is no assurance that the Partnership will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, the Partnership may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any vulnerability to cyber-attacks.

 

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Loss of Partnership information and computer systems could adversely affect the Partnership’s business.

 

The Partnership will be heavily dependent on information systems and computer based programs of its operators, including well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in the hardware or software network infrastructure, possible consequences include the Partnership’s loss of communication links, inability of the Partnership’s operators to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on the Partnership’s business.

 

Oil and gas exploration and production activities are complex and involves risks that could lead to legal proceedings resulting in the incurrence of substantial liabilities.

 

Like many oil and gas companies, the Partnership will be from time to time involved in various legal and other proceedings in the ordinary course its business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on the Partnership because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in the Partnership’s business practices, which could materially and adversely affect the Partnership’s business, operating results and financial condition. Accruals for such liabilities, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

 

Risks Related to the JOBS Act

 

The Partnership is an emerging growth company under the JOBS Act and it intends to take advantage of reduced disclosure and governance requirements applicable to emerging growth companies, which could result in the Partnership’s common units being less attractive to investors.

 

The Partnership is an emerging growth company, as defined in the JOBS Act, and it intends to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in the Partnership’s periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. The Partnership expects to continue to take advantage of these reporting exemptions until the Partnership is no longer an emerging growth company, which in certain circumstances could be for up to five years.

 

The JOBS Act will allow the Partnership to postpone the date by which it must comply with certain laws and regulations intended to protect investors and reduce the amount of information provided in reports filed with the SEC.

 

The JOBS Act is intended to reduce the regulatory burden on emerging growth companies. The Partnership meets the definition of an emerging growth company and so long as the Partnership qualifies as an emerging growth company, the Partnership may, among other things:

 

be exempt from the provisions of Section 404(b) of the Sarbanes-Oxley Act requiring that the Partnership’s independent registered public accounting firm provide an attestation report on the effectiveness of its internal control over financial reporting;

be exempt from the “say on pay” provisions (requiring a non-binding shareholder vote to approve compensation of certain executive officers) and the “say on golden parachute” provisions (requiring a non-binding shareholder vote to approve golden parachute arrangements for certain executive officers in connection with mergers and certain other business combinations) of the Dodd-Frank Act and certain disclosure requirements of the Dodd-Frank Act relating to compensation of the Partnership’s chief executive officer;

be permitted to omit the detailed compensation discussion and analysis from proxy statements and reports filed under the Securities Exchange Act of 1934 and instead provide a reduced level of disclosure concerning executive compensation; and

be exempt from any rules that may be adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report on the financial statements.

 

The Partnership currently intends to take advantage of all of the reduced regulatory and reporting requirements that will be available to it so long as the Partnership qualifies as an emerging growth company.

 

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Tax Risks to Common Unitholders

 

The Partnership’s tax treatment depends on its status as a partnership for U.S. federal income tax purposes and not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service treats the Partnership as a corporation or the Partnership becomes subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution to the Partnership’s common unitholders.

 

The anticipated after-tax economic benefit of an investment in the common units depends largely on the Partnership being treated as a partnership for U.S. federal income tax purposes. The Partnership has not requested, and does not plan to request, a ruling from the Internal Revenue Service (“IRS”) on this or any other tax matter affecting it.

 

If the Partnership was treated as a corporation for U.S. federal income tax purposes, the Partnership would pay federal income tax on the Partnership’s taxable income at the corporate tax rate, which, effective January 1, 2018, is currently a maximum of 21% and likely would pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon the Partnership as a corporation, cash available for distribution to you would be substantially reduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flows and after-tax return to the unitholders, likely causing a substantial reduction in the value of the Partnership’s common units.

 

Current law may change so as to cause the Partnership to be treated as a corporation for U.S. federal income tax purposes or otherwise subject the Partnership to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states have ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such taxes on the Partnership will reduce the cash available for distribution to a unitholder.

 

An IRS contest of the Partnership’s U.S. federal income tax positions may adversely affect the value for the Partnership’s common units, and the cost of any IRS contest will reduce the Partnership’s cash available for distribution to the Partnership’s unitholders.

 

The Partnership has not requested a ruling from the IRS with respect to its treatment as a partnership for U.S. federal income tax purposes or any other matter affecting the Partnership. It may be necessary to resort to administrative or court proceedings to sustain some or all of the Partnership’s counsel’s conclusions or the positions the Partnership takes. A court may not agree with all of the Partnership’s counsel’s conclusions or positions the Partnership takes. Any contest with the IRS may materially and adversely impact the value of the Partnership’s units. In addition, costs incurred in any contest with the IRS will be borne indirectly by holders of common units and the General Partner because the costs will reduce the Partnership’s cash available for distribution.

 

You may be required to pay taxes on income from the Partnership even if you do not receive any cash distributions from the Partnership.

 

Because holders of the Partnership’s common units will be treated as partners to whom the Partnership will allocate taxable income which could be different in amount than the cash the Partnership distributes, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of the Partnership’s taxable income even if you receive no cash distributions from the Partnership. You may not receive cash distributions from the Partnership equal to your share of the Partnership’s taxable income or even equal to the tax liability that results from that income.

 

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If the IRS makes audit adjustments to the Partnership’s income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from the Partnership, in which case the Partnership’s cash available for distribution to unitholders might be substantially reduced and current and former unitholders may be required to indemnify the Partnership for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf.

 

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to the Partnership’s income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from the Partnership. To the extent possible under the new rules, the General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if the Partnership is eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although the General Partner may elect to have unitholders take such audit adjustment into account in accordance with their interests in the Partnership during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, the Partnership’s current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in the Partnership during the tax year under audit. If, as a result of any such audit adjustment, the Partnership is required to make payments of taxes, penalties and interest, cash available for distribution to unitholders might be substantially reduced and current and former unitholders may be required to indemnify the Partnership for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

 

You may not qualify for percentage depletion deductions, and even if you do so qualify, you will be required to determine, and maintain records supporting, your deduction.

 

Percentage depletion is generally available with respect to common unitholders who qualify under the independent producer exemption contained in Code Section 613A(c). For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. The Partnership cannot determine whether or provide any assurance that you will qualify as an independent producer. Further, if you do qualify as an independent producer, you are required to determine the amount of your allowed percentage depletion deduction and maintain records supporting such determination.

 

The Partnership cannot assure you that it will meet the requirements for you to deduct intangible drilling and development costs.

 

Federal tax law places substantial limits on taxpayers’ ability to deduct intangible drilling and development costs (“IDCs”). Generally speaking, an “operator” is permitted to elect to currently deduct, or capitalize and deduct ratably over a 60-month period, costs that are properly characterized as IDCs that the operator incurs in connection with the drilling and development of oil and natural gas wells. For purposes of deducting IDCs, an “operator” is generally defined as one that owns a working or an operating interest in an oil or gas well. If the Partnership determines that it is an “operator” with respect to its oil and gas wells, the Partnership’s determination is not binding on the IRS. The IRS may assert that the Partnership is not an “operator” with respect to one or more of its oil or gas wells at the time that IDCs are incurred. If the IRS were successful in such a challenge, the Partnership and, therefore, you, would not be entitled to deduct the IDCs incurred in connection with such wells.

 

If the Partnership is eligible to deduct IDCs, the Partnership cannot assure you that IDCs will be deductible in any given year.

 

If the Partnership is deemed to be an operator with respect to one or more of its oil or gas wells, its classification of a cost as an IDC is not binding on the IRS. The IRS may reclassify an item classified by the Partnership as an IDC as a cost that must be capitalized or that is not deductible.

 

The IRS could challenge the timing of the Partnership’s deductions of IDCs, which could result in an increase your tax liabilities.

 

IDCs are generally deductible when the well to which the costs relate is drilled. In some cases, IDCs may be paid in one year for a well that is not drilled until the following year. In those cases, the prepaid IDCs will not be deductible until the year when the well is drilled unless (i) drilling on the well to which the prepayment relates starts within 90 days after the end of the year the prepayment is made or (ii) it is reasonable to expect that the well will be fully drilled within 3-1/2 months of the prepayment. All of the Partnership’s wells may not be drilled during the year when the Partnership pays IDCs pursuant to a drilling contract. As a result, the Partnership could fail to satisfy the requirements to deduct the IDCs in the year when paid and/or the IRS may challenge the timing of the Partnership’s deduction of prepaid IDCs.

 

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The deduction for IDCs may not be available to you if you do not have passive income.

 

If you invest in the Partnership, your share of the Partnership’s deduction for IDCs in the year you invest will be a passive loss that can be used to offset only passive income. Such deductions cannot be used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends and interest income. Any unused passive loss from IDCs may be carried forward indefinitely by you to offset your passive income in subsequent taxable years. Certain taxpayers are not subject to the passive loss rules.

 

On the disposition of property by the Partnership or of common units by you, certain deductions for IDCs, depletion, and depreciation must be recaptured as ordinary income.

 

You may be required to recapture as ordinary income certain deductions for IDCs, depletion, and depreciation on disposition of property by the Partnership or on disposition of the Partnership’s common units.

 

Tax gain or loss on disposition of common units could be more or less than expected.

 

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that unit, even if the price is less than your original cost. As discussed above, a substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

 

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

 

Investment in common units by tax-exempt entities, such as individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. For example, much of the Partnership’s income allocated to organizations that are exempt from federal income tax, including IRAs, will be unrelated business taxable income and will be taxable to them. Similarly, much of the Partnership’s income allocable to non-U.S. persons will constitute effectively connected U.S. trade or business income, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of the Partnership’s taxable income. As a result, distributions to a non-U.S. person will be subject to withholding at the highest applicable effective tax rate and a non-U.S. person who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.

 

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. person’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interest in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. person should consult a tax advisor before investing in our common units.

 

Holders of common units may be subject to state and local taxes and tax return filing requirements in states where they do not live as a result of investing in the Partnership’s common units.

 

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which the Partnership does business or owns property, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements.

 

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

 

The U.S. legislature regularly considers budget proposals that may impact many tax incentives and deductions that are currently used by U.S. oil and gas companies. Among others, budget provisions may include: repeal of the deduction of IDC; repeal of the percentage depletion deduction for oil and gas properties; repeal of the domestic manufacturing tax deduction for oil and gas companies; and an increase in the amortization period for geological and geophysical costs of independent producers.

 

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The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could increase the amount of the Partnership’s taxable income allocable to you. The Partnership is unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any modifications to the federal income tax laws or interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in the Partnership’s common units.

 

Holders of common units may be subject to limit on the ability to deduct interest expense incurred by the Partnership.

 

In general, the Partnership is entitled to a deduction for interest paid or accrued on indebtedness properly allocable to the Partnership’s trade or business during its taxable year. However, for taxable years beginning after December 31, 2017, the Partnership’s deduction for “business interest” is limited to the sum of the Partnership’s business interest income and 30% of “adjusted taxable income.” For the purposes of this limitation, the Partnership’s adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. The amount of the Partnership’s interest expense deductible by any holder of common units may also be limited based upon such limited partner’s individual circumstance.

 

Item 1B.  Unresolved Staff Comments

 

None

 

Item 2.  Properties

 

Information regarding the Partnership’s properties is contained in Item 1 – Business, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Item 8 – Financial Statements and Supplementary Data: Note 3. Oil and Gas Investments, appearing elsewhere within this Annual Report on Form 10-K.

 

Item 3.  Legal Proceedings

 

At the end of the period covered by this Annual Report on Form 10-K, the Partnership was not a party to any material, pending legal proceedings.

 

Item 4.  Mine Safety Disclosures

 

Not applicable.

 

 

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Part II

 

Item 5.  Market For Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

 

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. 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. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, and the General Partner received Incentive Distribution Rights. As of December 31, 2018, the Partnership had completed the sale of 7,857,359 common units for total gross proceeds of $154.5 million and proceeds net of offering costs including selling commissions and marketing expenses of $144.6 million. As of December 31, 2018, 9,774,220 common units remained unsold. As of March 29, 2019, the common units were held by approximately 3,000 unitholders. The offering was extended in February 2019 and in accordance with the prospectus, 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 December 31, 2018, the Managing Dealer Incentive Fees are up to approximately $6.2 million, subject to Payout (defined below).

 

There is currently no established public trading market in which the Partnership’s common units are traded. The net proceeds of the ongoing best-efforts offering as of December 31, 2018 have been used as follows:

 

Units Registered

                             
        2,631,579  

Units

  $ 19.00  

per unit

  $ 50,000,001  
        15,000,000  

Units

  $ 20.00  

per unit

    300,000,000  

Totals:

      17,631,579  

Units

            $ 350,000,001  
                               
                               

Units Sold

                             
        2,631,579  

Units

  $ 19.00  

per unit

  $ 50,000,001  
        5,225,780  

Units

  $ 20.00  

per unit

    104,515,599  

Totals:

      7,857,359  

Units

            $ 154,515,600  
                               
                               
                               

Expenses of Issuance and Distribution of Units

       
 1.   Underwriting commissions   $ 9,270,936  
 2.   Expenses of underwriters     -  
 3.   Direct or indirect payments to directors or officers of the Partnership or their associates, or to affiliates of the Partnership     -  
 4.   Fees and expenses of third parties     595,784  
Total Expenses of Issuance and Distribution of Common Shares     9,866,720  

Net Proceeds to the Partnership

  $ 144,648,880  
                               
1.   Purchase of oil, gas and natural gas liquids properties (net of debt, proceeds and repayment including interest and acquisition costs)   $ 132,191,351  
 2.   Deposits and other costs associated with potential oil, natural gas and natural gas liquids acquisitions     -  
 3.   Repayment of other indebtedness, including interest expense paid     -  
 4.   Investment and working capital     12,457,529  
 5.   Fees and expenses of third parties     -  
 6.   Other     -  

Total Application of Net Proceeds to the Partnership

  $ 144,648,880  

 

43

 

Distribution Policy

 

Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units.  Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.

 

The Partnership Agreement provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

 

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

 

 

First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

 

 

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

 

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

 

For the year ended December 31, 2018, the Partnership paid distributions of $1.396164 per common unit, or $7.0 million. For the year ended December 31, 2017, the Partnership paid distributions of $0.598357 per common unit, or $1.5 million. The Partnership began paying distributions upon reaching the minimum offering in July 2017.

 

Neither the Partnership nor the General Partner has adopted an equity compensation plan.

 

Item 6.  Selected Financial Data

 

Not applicable.

 

44

 

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion and analysis should be read in conjunction with Item 8 – the Consolidated Financial Statements and Notes thereto, the introduction of Part I regarding “Forward-Looking Statements,” and Item 1A – Risk Factors appearing elsewhere in this Annual Report on Form 10-K.

 

Overview

 

Energy Resources 12, L.P. (the “Partnership”) was formed as a Delaware limited partnership. The general partner is Energy Resources 12 GP, LLC (the “General Partner”). 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. 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. As of December 31, 2018, the Partnership had sold 7.9 million common units for gross proceeds of $154.5 million and proceeds net of offering costs of $144.6 million. The offering will expire on November 18, 2019 or upon the sale of 17,631,579 common units, whichever occurs first.

 

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 December 31, 2018, the Partnership had an approximate 5.9% non-operated working interest in the Bakken Assets, consisting of 257 producing wells, 37 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”). Since February 2018, monthly average oil prices (based on daily settlements of monthly contracts traded on the NYMEX) ranged from a low of $48.97 per barrel in December 2018 to a high of $70.98 in July 2018. The monthly average of $70.98 per barrel of oil in July 2018 represented the highest monthly average since November 2014. Since February 2018, monthly averages for natural gas prices have ranged from $2.67 per MMBtu in February 2018 to $4.09 per MMBtu in November 2018.

 

The average daily NYMEX prices for oil and natural gas since completing Acquisition No. 1 on February 1, 2018 were $65.07 per barrel of oil and $3.09 per MMBtu of natural gas, respectively.

 

45

 

Factors contributing to uncertainty within the industry 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.

 

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 93 wells.

 

As specified by the SEC, the prices for oil, natural gas and NGL used to calculate the Partnership’s reserves are based on the unweighted arithmetic average prices as of the first day of each of the twelve months during the year ended December 31, 2018. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2018 were $65.56 per barrel of oil and $3.10 per MMcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2018 were $59.56 per barrel of oil, $2.43 per MMcf of natural gas and $20.25 per barrel of NGL.

 

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. Other than the payment of fees and expenses described herein, the Partnership had no other operations prior to the acquisition of the Bakken Assets. Because the Partnership had no revenues in fiscal 2017, there is no comparison of the Partnership’s results of operations for the year ended December 31, 2018 to the Partnership’s results of operations for the year ended December 31, 2017, except as otherwise indicated below.

 

In evaluating financial condition and operating performance, the most important indicators on which the Partnership focuses are (1) total quarterly sold 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 eleven-month period from February 1, 2018 to December 31, 2018 (which reflects the respective periods of ownership of Acquisitions No. 1 and No. 2).

 

   

Eleven Months Ended December 31,

   

2018

   

Percent of Revenue

   

Total revenues

  $ 25,721,036       100.0

%

 

Production expenses

    5,694,187       22.1

%

 

Production taxes

    2,293,761       8.9

%

 

Depreciation, depletion, amortization and accretion

    4,928,439       19.2

%

 

General, administration and other expense

    1,614,910       6.3

%

 
                   

Sold production (BOE):

                 

Oil

    405,581            

Natural gas

    53,240            

Natural gas liquids

    42,329            

    Total

    501,150            
                   

Average sales price per unit:

                 

Oil (per Bbl)

  $ 58.66            

Natural gas (per Mcf)

    3.30            

Natural gas liquids (per Bbl)

    20.73            

Combined (per BOE)

    51.32            
                   

Average unit cost per BOE:

                 

Production expenses

    11.36            

Production taxes

    4.58            

Depreciation, depletion, amortization and accretion

    9.83            
                   

Capital expenditures

  $ 15,420,911            

 

46

 

Oil, Natural Gas and NGL Sales

 

For the eleven months from February 1, 2018 to December 31, 2018, revenues for oil, natural gas and NGL sales were $25.7 million. Revenues for the sale of crude oil were $23.8 million, which resulted in a realized price of $58.66 per barrel. Revenues for the sale of natural gas were $1.1 million, which resulted in a realized price of $3.30 per Mcf. Revenues for the sale of NGLs were $0.9 million, which resulted in a realized price of $20.73 per BOE of production. Average realized prices in the fourth quarter of 2018 were approximately $50.56 per barrel of oil, $3.91 per Mcf of natural gas and $18.20 per BOE of NGL.

 

The Partnership’s sold production for the Bakken Assets was approximately 2,175 BOE per day for the fourth quarter of 2018. Production volumes per day fluctuated throughout 2018 due to the timing of well completions. Since the Partnership’s first acquisition in February 2018, approximately 29 new wells were 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 2,250 BOE per day for the year ended December 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 37 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 contract in effect for the extraction, transportation and treatment of natural gas.

 

For the eleven months from February 1, 2018 to December 31, 2018, production expenses were $5.7 million, and production expenses per BOE of sold production were $11.36, respectively. Production expenses for the fourth quarter of 2018 were $2.5 million, and production expenses per BOE of production were $12.40.

 

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 NGL to total sales. Production taxes for the eleven months from February 1, 2018 to December 31, 2018 were $2.3 million, or 9% of total revenue. Production taxes for the fourth quarter of 2018 were $0.8 million, or 9% of total 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 eleven months from February 1, 2018 to December 31, 2018 was $4.9 million, and DD&A per BOE of production was $9.83. DD&A for the fourth quarter of 2018 was $1.9 million, and DD&A per BOE of production was $9.43.

 

General, Administrative and Other Expense

 

The principal components of general and administrative expense are accounting, legal, advisory and consulting fees. General and administrative costs for the years ended December 31, 2018 and 2017 were $1.6 million and $0.1 million, respectively. General and administrative expenses for the year ended December 31, 2018 exceeded those of the prior year 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 a rise in year-to-date accounting, legal and consulting and advisory fees.

 

47

 

Interest Income (Expense), net

 

Interest expense, net, for the year ended December 31, 2018 was $1.7 million, and interest income, net, for the year ended December 31, 2017 was $0.1 million. The primary component of Interest expense, net, during 2018 was the interest expense incurred on the Partnership’s revolving credit facility. In comparison, the primary component of Interest income, net, during 2017 was interest income earned on proceeds from the Partnership’s ongoing offering prior to completing an acquisition of oil and gas properties.

 

Derivative Instruments

 

In September 2018 and December 2018, the Partnership entered into derivative contracts with the objective to manage the commodity price risk on future oil and natural gas production. As of December 31, 2018, the Partnership’s outstanding derivative contract (costless collars) was in a gain position based upon the contract’s estimated fair market value at the balance sheet date. Based upon the estimated fair value of the derivative contract as of December 31, 2018, the Partnership recorded a mark-to-market gain of approximately $0.9 million. 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 gain recorded by the Partnership does not represent an actual settlement and no payment was received from the counterparty in 2018. There were no gains or losses on the Partnership’s hedge settlements in 2018. 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 Credit Facility maturity date of August 31, 2021.

 

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 production as of December 31, 2018.

 

   

Costless Collar

Volumes (Bbl)

 

Weighted Average

Floor / Ceiling Prices ($)

01/2019 - 12/2019

    266,000  

45.00 / 60.35

01/2020 - 06/2020

    107,000  

45.00 / 61.20

      373,000    

 

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 alternatives to, net income (loss), 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 Company’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 terms exactly as the Partnership defines such terms, 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 year ended December 31, 2018.

 

   

Year Ended
December 31, 2018

 

Net income

  $ 10,366,029  

Interest expense, net

    1,703,327  

Depreciation, depletion, amortization and accretion

    4,928,439  

Exploration expenses

    -  

Non-cash gain on mark-to-market of derivatives

    (879,617

)

   Adjusted EBITDAX

  $ 16,118,178  

 

48

 

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 December 31, 2018, the Lender commitment was $40.0 million and the interest rate for the Credit Facility was approximately 6.25%. At December 31, 2018, the outstanding balance on the Credit Facility was $39.5 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:

 

 

a maximum leverage ratio

 

a minimum current ratio

 

maximum distributions

 

The Partnership was in compliance with the applicable covenants at December 31, 2018.

 

49

 

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 December 31, 2018, the Dealer Manager Incentive Fees are approximately $6.2 million, subject to Payout (defined below). As of December 31, 2018, the Partnership had completed the sale of 7.9 common units for gross proceeds of approximately $154.5 million and proceeds net of offering costs of approximately $144.6 million. 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.

 

Distributions

 

Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units.  Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.

 

The Partnership Agreement provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

 

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

 

 

First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

 

 

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

 

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

 

For the year ended December 31, 2018, the Partnership paid distributions of $1.396164 per common unit, or $7.0 million. For the year ended December 31, 2017, the Partnership paid distributions of $0.598357 per common unit, or $1.5 million. The Partnership generated $10.8 million in cash flow from operations for the year ended December 31, 2018.

 

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 the Partnership’s properties ability to increase its cash generated from operations. 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 Gas Properties

 

The Partnership incurred approximately $15.4 million in capital expenditures for the period from February 1, 2018 to December 31, 2018. The Partnership expects to invest approximately $15 to $25 million in capital expenditures during 2019, including $10 to $15 million in capital expenditures to complete the 37 wells in process at December 31, 2018. In addition, the Partnership anticipates that it may be obligated to invest an additional $75 to $85 million in drilling capital expenditures from 2020 through 2023 to retain its approximate 5.9% working interest in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements or North Dakota statutes governing the Bakken Assets.

 

50

 

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, the timing of such activities and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast for 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 and would be subject to a non-consent penalty.

 

Contractual Commitments

 

The following is a summary of the Partnership’s significant contractual obligations as of December 31, 2018:

 

           

Payments Due by Period (in thousands)

 
   

Total

   

1 year

   

2-3 years

   

4-5 years

   

Over 5 years

 

Revolving credit facility

  $ 39,500     $ -     $ 39,500     $ -     $ -  

Estimated interest payments (1)

    6,675       2,504       4,171       -       -  

Capital expenditures (2)

    13,153       13,153       -       -       -  
    $ 59,328     $ 15,657     $ 43,671     $ -     $ -  

 


(1)

Interest payments assume no principal repayments (aside from those already made in January 2019) until the Credit Facility maturity date of August 31, 2021 and are estimated using the Partnership’s interest rate at December 31, 2018 of 6.25%.

 

 

(2)

The Partnership executed authorization for expenditures (AFEs) in conjunction with the 37 in-progress wells at December 31, 2018. Based upon these AFEs, the Partnership estimates remaining capital expenditures for these wells to be approximately $13.2 million and will be paid during 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 8. Related Parties in Part II, Item 8 – Financial Statements and Supplementary Data and in Part III, Item 13 — Certain Relationships and Related Transactions, and Director Independence, appearing elsewhere in this Annual Report on Form 10-K.

 

Critical Accounting Policies

 

The discussion and analysis of the Partnership’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these consolidated financial statements requires the Partnership to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. Certain of the Partnership’s accounting policies involve estimates and assumptions to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. The Partnership bases these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as the Partnership’s operating environment changes and as new events occur.

 

51

 

The Partnership’s critical accounting policies are important to the portrayal of both its financial condition and results of operations and require the Partnership to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. The Partnership would report different amounts in its consolidated financial statements, which could be material, if the Partnership used different assumptions or estimates. The Partnership believes that the following are the critical accounting policies used in the preparation of its consolidated financial statements.

 

Oil and Natural Gas Properties

 

The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

 

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

 

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

 

The successful efforts method of accounting can have a significant impact on the operational results reported when the Partnership is entering a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial, which will result in additional exploration expenses when incurred.

 

Impairment

 

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of a property exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the property, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

 

52

 

Estimates of Oil, Natural Gas and Natural Gas Liquids Reserves

 

The Partnership’s estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production, both of which provide accurate forecasts. Non–producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. These methods provide accurate forecasts due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

 

The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, the Partnership must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of the Partnership’s reserves. Independent reserve engineers prepare the Partnership’s reserve estimates at the end of each year.

 

Despite the inherent imprecision in these engineering estimates, the Partnership’s reserves are used throughout the Partnership’s financial statements. For example, since the Partnership uses the units–of–production method to amortize the costs of our oil and natural gas properties, the quantity of reserves could significantly impact its depreciation, depletion and amortization expense. The Partnership’s reserves are also the basis of the Partnership’s supplemental oil and natural gas disclosures.

 

Accounting for Asset Retirement Obligations

 

The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The Partnership’s removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

 

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the 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.

 

Revenue Recognition

 

Revenues associated with the sales of crude oil, natural gas, and natural gas liquids are recognized at the point in time when the customer obtains control of the asset. In evaluating when a customer has control of the asset, the Partnership primarily considers whether the transfer of legal title and physical delivery has occurred, whether the customer has significant risks and rewards of ownership, and whether the customer has accepted delivery and a right to payment exists. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

 

53

 

The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined.

 

Recent Accounting Standards

 

See Note 2. Summary of Significant Accounting Policies in Part II, Item 8 – Financial Statements and Supplementary Data for a summary of recent accounting standards.

 

Subsequent Events

 

In January 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 $5.1 million and proceeds net of selling and marketing costs of approximately $4.8 million.

 

In January 2019, the Partnership declared and paid $0.8 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

 

In February 2019, the Partnership closed on the issuance of approximately 0.2 million common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $4.4 million and proceeds net of selling and marketing costs of approximately $4.2 million.

 

In February 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 March 2019, the Partnership entered into additional costless collar derivative contracts to hedge a portion of the Partnership’s future oil and natural gas production for the period from April 2019 to September 2020. The contracts cover approximately 108,000 BOE of oil and natural gas production for the stated period. The Partnership did not pay or receive a premium related to the costless collar agreements.

 

In March 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 $6.9 million and proceeds net of selling and marketing costs of approximately $6.5 million.

 

In March 2019, the Partnership declared and paid $1.1 million, or $0.134247 per outstanding common unit, in distributions to its holders of common units.

 

Item 7A. Quantitative and Qualitative Disclosure about Market Risk

 

Information regarding the Partnership’s hedging programs to mitigate commodity risks is contained in Item 1 – Business, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Item 8 – Financial Statements and Supplementary Data: Note 6. Risk Management, appearing elsewhere within this Annual Report on Form 10-K.

 

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 – Business, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Item 8 – Financial Statements and Supplementary Data: Note 4. Debt, appearing elsewhere within this Annual Report on Form 10-K.

 

54

 

Item 8.  Financial Statements and Supplementary Data

 

Financial Statements

 

Report of Independent Registered Public Accounting Firm

 

To the Shareholders and the General Partner of Energy Resources 12, L.P.

 

Opinion on the Financial Statements

 

We have audited the accompanying consolidated balance sheets of Energy Resources 12, L.P. (the “Partnership”) as of December 31, 2018 and 2017, the related consolidated statements of operations, Partners’ equity, and cash flows for each of the two years ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2018 and 2017, and the results of operations and its cash flows for each of the two years ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

 

Basis for Opinion

 

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion.

 

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

 

/s/ Ernst & Young LLP

 

We have served as the Partnership’s auditor since 2017.

 

Richmond, Virginia

March 29, 2019

 

55

 

Energy Resources 12, L.P.

Consolidated Balance Sheets

 

   

December 31,

   

December 31,

 
   

2018

   

2017

 
                 

Assets

               

Cash and cash equivalents

  $ 9,682,402     $ 46,859,728  

Oil, natural gas and natural gas liquids revenue receivable

    3,431,064       -  

Derivative asset

    644,786       -  

Deposit for potential acquisition

    -       8,750,000  

Deferred acquisition costs

    -       4,884,208  

Total Current Assets

    13,758,252       60,493,936  
                 

Oil and natural gas properties, successful efforts method, net of accumulated depreciation,

depletion and amortization of $4,889,806 and $0, respectively

    182,078,667       -  

Derivative asset - noncurrent

    234,831       -  

Other assets, net

    1,512,941       -  

Total Assets

  $ 197,584,691     $ 60,493,936  
                 

Liabilities

               

Accounts payable and accrued expenses

  $ 11,488,175     $ 164,786  

Due to related parties

    212,117       5,283,623  

Total Current Liabilities

    11,700,292       5,448,409  
                 

Revolving credit facility

    39,500,000       -  

Asset retirement obligations

    383,255       -  

Total Liabilities

    51,583,547       5,448,409  
                 

Partners’ Equity

               

Limited partners' interest (7,857,359 and 3,191,231 common units issued and outstanding, respectively)

    146,001,359       55,045,742  

General partner's interest

    (215

)

    (215

)

Total Partners’ Equity

    146,001,144       55,045,527  
                 

Total Liabilities and Partners’ Equity

  $ 197,584,691     $ 60,493,936  

 

See notes to consolidated financial statements.

 

56

 

Energy Resources 12, L.P.

Consolidated Statements of Operations

 

   

Year Ended

   

Year Ended

 
   

December 31, 2018

   

December 31, 2017

 
                 

Revenues

               

Oil

  $ 23,790,225     $ -  

Natural gas

    1,053,135       -  

Natural gas liquids

    877,676       -  

Total revenue

    25,721,036       -  
                 

Operating costs and expenses

               

Production expenses

    5,694,187       -  

Production taxes

    2,293,761       -  

Transaction costs

    -       525,000  

General and administrative expenses

    1,614,910       99,410  

Depreciation, depletion, amortization and accretion

    4,928,439       -  

Total operating costs and expenses

    14,531,297       624,410  
                 

Operating income (loss)

    11,189,739       (624,410

)

                 

Interest income (expense), net

    (1,703,327

)

    114,163  

Gain on derivatives

    879,617       -  

Total other expense, net

    (823,710

)

    114,163  
                 

Net income (loss)

  $ 10,366,029     $ (510,247

)

                 

Basic and diluted net income (loss) per common unit

  $ 2.04     $ (0.48

)

                 

Weighted average common units outstanding - basic and diluted

    5,091,922       1,067,941  

 

See notes to consolidated financial statements.

 

57

 

Energy Resources 12, L.P.

Consolidated Statements of Partners’ Equity

 

   

Limited Partner

   

General Partner

   

Total Partners'

 
   

Amount

   

Amount

   

Equity

 
                         

Balance December 31, 2016

  $ 723     $ 7     $ 730  
                         

Net proceeds from issuance of common units

    57,014,432       -       57,014,432  

Distributions to organizational limited partner

    (990

)

    -       (990

)

Distributions declared and paid to common units ($0.598357 per unit)

    (1,458,398

)

    -       (1,458,398

)

2017 Net loss

    (510,025

)

    (222

)

    (510,247

)

Balance December 31, 2017

    55,045,742       (215

)

    55,045,527  
                         

Net proceeds from issuance of common units

    87,634,447       -       87,634,447  

Distributions declared and paid to common units ($1.396164 per unit)

    (7,044,859

)

    -       (7,044,859

)

2018 Net income

    10,366,029       -       10,366,029  

Balance December 31, 2018

  $ 146,001,359     $ (215

)

  $ 146,001,144  

 

See notes to consolidated financial statements.

 

58

 

Energy Resources 12, L.P.

Consolidated Statements of Cash Flows

 

   

Year Ended

   

Year Ended

 
   

December 31, 2018

   

December 31, 2017

 
                 

Cash flow from operating activities:

               

Net income (loss)

  $ 10,366,029     $ (510,247

)

                 

Adjustments to reconcile net income (loss) to cash from operating activities:

               

Depreciation, depletion, amortization and accretion

    4,928,439       -  

Gain on mark-to-market of derivatives

    (879,617

)

    -  

Non-cash expenses, net

    189,118       -  
                 

Changes in operating assets and liabilities:

               

Oil, natural gas and natural gas liquids revenue receivable

    (4,683,138

)

    -  

Deferred acquisition costs

    -       (4,190

)

Due to related parties

    (346,506

)

    -  

Accounts payable and accrued expenses

    1,256,020       560,832  
                 

Net cash flow provided by operating activities

    10,830,345       46,395  
                 

Cash flow from investing activities:

               

Cash paid for acquisition of oil and natural gas properties

    (161,249,883

)

    -  

Deposit for acquisition of oil and natural gas properties

    -       (8,750,000

)

Additions to oil and natural gas properties

    (5,144,076

)

    -  
                 

Net cash flow used in investing activities

    (166,393,959

)

    (8,750,000

)

                 

Cash flow from financing activities:

               

Cash paid for loan costs

    (1,702,059

)

    -  

Proceeds from line of credit

    -       229,000  

Payments on line of credit

    -       (229,000

)

Proceeds from term loan

    25,000,000       -  

Payments on term loan

    (25,000,000

)

    -  

Proceeds from advance from member of general partner

    7,000,000       -  

Payments on advance from member of general partner

    (7,000,000

)

    -  

Net proceeds from revolving credit facility

    39,500,000       -  

Net proceeds related to issuance of common units

    87,633,206       57,020,731  

Distributions paid to limited partners

    (7,044,859

)

    (1,458,398

)

                 

Net cash flow provided by financing activities

    118,386,288       55,562,333  
                 

(Decrease) increase in cash and cash equivalents

    (37,177,326

)

    46,858,728  

Cash and cash equivalents, beginning of period

    46,859,728       1,000  
                 

Cash and cash equivalents, end of period

  $ 9,682,402     $ 46,859,728  
                 

Interest paid

  $ 1,557,862     $ 1,420  
                 

Supplemental non-cash information:

               

Accrued deferred costs for potential acquisition

  $ -     $ 4,880,018  

 

See notes to consolidated financial statements.

 

59

 

Energy Resources 12, L.P.

Notes to Consolidated Financial Statements

December 31, 2018

 

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, will expire on November 18, 2019, provided that the offering will be terminated if all of the common units are sold before then.

 

As of December 31, 2018, the Partnership owned an approximate 5.9% non-operated working interest in 257 currently producing wells and 37 wells in various stages of the drilling and completion process, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 14 third-party operators on behalf of the Partnership and other working interest owners.

 

The general partner of the Partnership is Energy Resources 12 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. David Lerner Associates, Inc. (the “Managing Dealer”), is acting as the dealer manager for the offering of the common units.

 

The Partnership’s fiscal year ends on December 31. 

 

Note 2.  Summary of Significant Accounting Policies

 

Basis of Presentation

 

The accompanying financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”).

 

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 December 31, 2018, the Partnership had sold 7.9 million common units for gross proceeds of $154.5 million and proceeds net of offering costs of $144.6 million.

 

Property and Depreciation, Depletion and Amortization

 

The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

 

60

 

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

 

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

 

Impairment

 

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of a property exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the property, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

 

Accounts Receivable and Concentration of Credit Risk

 

Substantially all of the Partnership’s accounts receivable are due from purchasers of oil, natural gas and NGLs or operators of the oil and natural gas properties. Oil, natural gas and NGL sales receivables are generally unsecured. This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2018, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. For the year ended December 31, 2018, the Partnership’s oil, natural gas and NGL sales were through thirteen operators; approximately 80% of the Partnership’s total revenue was generated through sales by four operators. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership.

 

Accounting for Asset Retirement Obligations

 

The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

 

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the 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.

 

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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 following table shows the activity for the year ended December 31, 2018 relating to the Partnership’s asset retirement obligations:

 

Balance as of January 1, 2018

  $ -  

Liabilities incurred on February 1, 2018 (Acquisition No. 1)

    133,155  

Liabilities incurred on August 31, 2018 (Acquisition No. 2)

    170,823  

Well additions

    40,644  

Accretion

    38,633  

Balance as of December 31, 2018

  $ 383,255  

 

Environmental Costs

 

As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved.

 

Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2018, there were no such costs accrued.

 

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.

 

Of these estimates and assumptions, management considers the estimation of oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (“SEC”), the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected NYMEX forward strip prices for oil, natural gas and NGL as estimated by management are used. Oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of oil, natural gas and NGL reserves used in formulating management’s overall operating decisions.

 

The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined.

 

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Revenue Recognition

 

Revenues associated with the sales of crude oil, natural gas, and natural gas liquids are recognized at the point in time when the customer obtains control of the asset. In evaluating when a customer has control of the asset, we primarily consider whether the transfer of legal title and physical delivery has occurred, whether the customer has significant risks and rewards of ownership, and whether the customer has accepted delivery and a right to payment exists. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

 

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 (loss), partners’ equity or cash flows.

 

Income Tax

 

The Partnership is taxed as a partnership for federal and state income tax purposes. No provision for income taxes has been recorded since the liability for such taxes is that of each of the partners rather than the Partnership. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners.

 

The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.

 

Net Income (Loss) per Common Unit

 

Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (loss) per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2018 and 2017. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 7) are not included in net income (loss) per common unit until such time that it is probable Payout (as discussed in Note 7) would occur.

 

Recently Adopted Accounting Standards

 

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606), that amends the former revenue recognition guidance and provides a revised comprehensive revenue recognition model with customers that contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017. The Partnership adopted this standard on January 1, 2018. The Partnership did not recognize any revenue for any period prior to adoption of this standard. The Partnership disaggregates its revenue on the face of the consolidated statements of operations for the years ended December 31, 2018.

 

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting model to enable entities to better portray their risk management activities in their financial statements and enhance the transparency and understandability of hedging activity. The standard simplifies the application of hedge accounting and reduces the administrative burden of hedge documentation requirements and assessing hedge effectiveness. The standard is effective for annual and interim periods beginning after December 15, 2018 with early adoption permitted. The standard requires a modified retrospective approach for all hedge relationships that exist on the date of adoption. The presentation and disclosure guidance is required only prospectively. The Partnership adopted this standard on January 1, 2018. As of January 1, 2018, the Partnership did not have any outstanding hedge positions; therefore, the adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements. The Partnership entered into derivative contracts in September and December 2018; refer to Note 6. Risk Management for additional information.

 

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Recently Issued Accounting Standards

 

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets as right-of-use assets and lease liabilities. The standard is effective for annual and interim periods beginning after December 15, 2018 with early adoption permitted. The Partnership expects to adopt this standard as of January 1, 2019. The Partnership has completed its review of its existing leases and has concluded there is no material impact to the Partnership’s consolidated financial statements and related disclosures.

 

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, subject to customary adjustments. 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 4. 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 accounted for Acquisition No. 1 as a purchase of a group of similar assets, and therefore capitalized transaction costs associated with this acquisition. These acquisition-related costs included, but were not limited to, fees for advisory and consulting (discussed below), due diligence, legal, accounting, engineering and environmental review services. The Partnership capitalized approximately $5.0 million in acquisition-related costs in conjunction with Acquisition No. 1. The Partnership also recorded an asset retirement obligation liability of approximately $0.1 million in conjunction with this acquisition. In addition, the Partnership adjusted the purchase price to reflect the operating revenues and expenses of Acquisition No. 1 between the acquisition effective date of September 1, 2017 and the closing date of February 1, 2018, in accordance with the closing conditions set forth in the purchase agreement. The net impact of the purchase price adjustments was a decrease to the purchase price of the asset of approximately $2.1 million.

 

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 4. 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 those listed above, 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 $4.6 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 4. Debt. The deferred loan costs are recorded as Other assets, net on the Partnership’s consolidated balance sheet.

 

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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 7. 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 7. 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 8. Related Parties below for additional information.

 

The following unaudited pro forma financial information for the years December 31, 2018 and 2017 have been prepared as if Acquisitions No.1 and No. 2 of the Bakken Assets had occurred on January 1, 2017. The unaudited pro forma financial information was derived from the historical statements of operations of the Partnership and the historical financial statements of the sellers of the Bakken Assets. The unaudited pro forma financial information does not purport to be indicative of the results of operations that would have occurred had the acquisition of the Bakken Assets and related financings occurred on the basis assumed above, nor is such information indicative of the Partnership’s expected future results of operations.

 

   

Year Ended

December 31, 2018

   

Year Ended

December 31, 2017

 
   

(Unaudited)

   

(Unaudited)

 

Revenues

  $ 43,067,089     $ 29,484,426  

Net income

  $ 18,604,782     $ 9,864,799  

 

As of December 31, 2018, the Partnership’s ownership of the Bakken Assets consisted of an approximate 5.9% non-operated working interest in 257 currently producing wells and 37 wells in various stages of the drilling and completion process.

 

From September 1, 2017, the effective date of Acquisition No. 1, to December 31, 2018, the Partnership has participated in the drilling of 93 wells, of which 56 have been completed and 37 wells are in various stages of completion at December 31, 2018. From February 1, 2018, the closing date of Acquisition No. 1, to December 31, 2018, the Partnership incurred approximately $15.4 million in capital drilling and completion costs. As of December 31, 2018, the Partnership had approximately $10.3 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 $13 million of capital expenditures to be incurred in 2019 to complete the 37 wells in various stages of completion at December 31, 2018.

 

Non-consent wells

 

Pursuant to the terms of the American Association of Professional Landmen Model Form Operating Agreement or North Dakota statute, each of which may govern operations between an operator and a non-operated working interest owner (“interest owner”), like the Partnership, an operator must notify an interest owner of its intention to drill a new well through submittal of a formal well proposal. The interest owner has the option to elect to participate in the drilling, completion and operating of the well and pay its proportionate share of all costs, or the interest owner may elect to non-consent the proposed well under the terms of the operating agreement or statute and bear no cost. If the interest owner elects to non-consent the proposed well, the interest owner is not obligated to pay any portion of the drilling, completion and operating expenses; however, the interest owner is then subject to a non-consent penalty under the terms of the operating agreement or North Dakota statute.

 

Through its 2018 acquisitions, the Partnership acquired 59 wells designated as non-consent wells, whereby a previous interest owner did not consent to participate in the drilling and completion of those wells. As a result, the Partnership is currently subject to non-consent penalties ranging from 200%-400%, meaning in general terms, the Partnership will remain in non-consent status and will not receive any revenue from these wells until the wells have satisfied the contractual or statutory penalties of 2-4 times payout of the expenses related to drilling, completion and operating the well. The Partnership may receive revenue or be responsible for operating and/or abandonment costs from all or a portion of these wells if the wells generate enough revenue to exceed the non-consent penalties described above.

 

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Note 4. 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 December 31, 2018, the Lender commitment was $40.0 million and the interest rate for the Credit Facility was approximately 6.25%. At December 31, 2018, the outstanding balance on the Credit Facility was $39.5 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:

 

 

a maximum leverage ratio

 

a minimum current ratio

 

maximum distributions

 

The Partnership was in compliance with the applicable covenants at December 31, 2018.

 

In February 2017, the Partnership obtained an unsecured line of credit with Bank of America in the principal amount of $500,000 to fund some of its offering and operating costs. On July 25, 2017, the Partnership repaid and extinguished the outstanding balance on the line of credit of $229,000, which bore interest at a variable rate based on the London InterBank Offered Rate (LIBOR), using proceeds from the sale of common units without a prepayment premium or penalty. Glade M. Knight, the General Partner’s Chief Executive Officer, and David S. McKenney, the General Partner’s Chief Financial Officer, had guaranteed repayment of the line of credit and did not receive any consideration in exchange for providing this guarantee.

 

As of December 31, 2018 and 2017, the Partnership’s outstanding debt balance was $39.5 million and $0, respectively. The outstanding balance at December 31, 2018 of $39.5 million approximates its fair market value. The Partnership estimated the fair value of its note payable 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.

 

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Note 5. 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:

 

 

Level 1: Quoted prices in active markets for identical assets

 

Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument

 

Level 3: Significant unobservable inputs

 

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 years ended December 31, 2018 and 2017, 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 Partnership did not have any financial assets and liabilities that were accounted for at fair value as of December 31, 2017, except for those instruments discussed below in “Fair Value of Other Financial Instruments.” 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 December 31, 2018.

 

   

Fair Value Measurements at December 31, 2018

 
   

Quoted Prices in
Active Markets for Identical Assets
(Level 1)

   

Significant Other Observable Inputs
(Level 2)

   

Significant Unobservable Inputs
(Level 3)

 

Commodity derivatives - current assets

  $ -     $ 644,786     $ -  

Commodity derivatives - current liabilities

    -       -       -  

Commodity derivatives - noncurrent assets

    -       234,831       -  

Commodity derivatives - noncurrent liabilities

    -       -       -  

Total

  $ -     $ 879,617     $ -  

 

The Level 2 instruments presented in the table above consist of 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 sheet as Derivative asset at December 31, 2018. See additional detail in Note 6. 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 4. Debt for the fair value discussion on the Partnership’s debt.

 

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Note 6. 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 September and December 2018, the Partnership entered into derivative contracts through June 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 December 31, 2018, the Partnership’s costless collar derivative instrument was in a net gain position; therefore, an asset of approximately $0.9 million, which approximates its fair value, has been recognized as Derivative asset (current and noncurrent) on the Partnership’s consolidated balance sheet.

 

The Partnership’s derivative contracts are costless collars, which are used to establish floor and ceiling prices on future anticipated oil and gas production. The Partnership did not pay or receive a premium related to the costless collar agreements. The contracts are settled monthly and there were no settlement payables or receivables at December 31, 2018. The Partnership’s September 2018 and December 2018 derivative contracts had been settled at December 31, 2018 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 follow table reflects the open costless collar instrument as of December 31, 2018.

 

Settlement Period

 

Basis

 

Oil (Barrels)

 

Floor / Ceiling Prices ($)

 

Fair Value of Asset / (Liability) at
December 31, 2018

 

01/01/19 - 12/31/19

 

NYMEX

    266,000  

45.00 / 60.35

  $ 644,786  

01/01/20 - 06/30/20

 

NYMEX

    107,000  

45.00 / 61.20

    234,831  
          373,000       $ 879,617  

 

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 gain of approximately $0.9 million for the year ended December 31, 2018, which was recorded on the consolidated statements of operations as Gain on derivatives.

 

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 5. Fair Value of Financial Instruments.

 

The Partnership’s outstanding derivative instruments are covered by an International Swap Dealers Association Master Agreement (“ISDA”) entered into with the counterparty. 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. The Partnership has netting arrangements with the counterparty that provide for offsetting payables against receivables from separate derivative instruments.

 

Note 7.  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.

 

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As of July 25, 2017, the Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit. As of December 31, 2018, the Partnership had completed the sale of 7.9 common units for gross proceeds of approximately $154.5 million and proceeds net of offering costs of approximately $144.6 million. 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.

 

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 December 31, 2018, the Dealer Manager Incentive Fees are approximately $6.2 million, subject to Payout (defined below).

 

Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units.  Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.

 

The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

 

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

 

First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

 

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

 

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

 

For the year ended December 31, 2018, the Partnership paid distributions of $1.396164 per common unit, or $7.0 million. For the year ended December 31, 2017, the Partnership paid distributions of $0.598357 per common unit, or $1.5 million.

 

Note 8.  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 December 31, 2018, the management fee paid to the General Partner for the year ended December 31, 2018 was approximately $537,000. The management fee paid to the General Partner is included in General and administrative expenses on the consolidated statements of operations.

 

69

 

The Partnership also will reimburse the General Partner for certain general and administrative costs. For the years ended December 31, 2018 and 2017, approximately $402,000 and $57,000 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 December 31, 2018, approximately $135,000 was due to a member of the General Partner and is included in Due to related parties in the consolidated balance sheets.

 

As discussed in Note 3. Oil and Gas Investments, in January 2018, the Partnership received an advance of $7.0 million from a member of the General Partner to partially fund Acquisition No. 1. The Partnership repaid a member of the General Partner in full in May 2018. The advance did not bear interest and the member of the General Partner did not receive any compensation for the advance. As discussed in Note 4. Debt, the Chief Executive Officer and Chief Financial Officer of the Partnership’s General Partner had guaranteed repayment of the Term Loan as well as the 2017 unsecured line of credit, of which both facilities were agreements with Bank of America. Neither the Chief Executive Officer nor the Chief Financial Officer received any consideration in exchange for providing the guarantee on either loan.

 

The Chief Executive Officer and Chief Financial Officer of the Partnership’s General Partner are also the Chief Executive Officer and Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, L.P. (“Energy 11”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11 that 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.

 

As noted above, the cost sharing agreement reduces the costs to the Partnership for accounting and asset management services provided through a member of the General Partner. In addition to certain accounting and asset management resources, the Partnership and Energy 11 share the rent expense for leased office space (leased from an affiliate of a member of the general partner of Energy 11) in Oklahoma City, Oklahoma along with the compensation due to the President of Energy 11’s general partner. For the year ended December 31, 2018, approximately $252,000 of expenses subject to the cost sharing agreement were incurred by the Partnership and have been or will be reimbursed to Energy 11. At December 31, 2018, approximately $77,000 was due from the Partnership to Energy 11 and is included in Due to related parties in the consolidated balance sheets.

 

As discussed in Note 3. Oil and Gas Investments, in November 2017 and June 2018, the Partnership engaged REI to perform advisory and consulting services, including supporting the Partnership through closing, financing and post-closing on Acquisitions No. 1 and No. 2. REI is owned by entities that are controlled by Messrs. Keating and Mallick and has engaged Cliff Merritt, President of Energy 11 GP, LLC, to support its operations. With the fees received from the Partnership for advisory and consulting services, REI paid certain personnel utilized by Energy 11 and the Partnership, including Mr. Merritt, an aggregate total of $500,000. 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 disposes any or all of the Bakken Assets, if surplus funds were available after Payout to the holders of the Partnership’s common units, as defined in Note 7. Capital Contribution and Partners’ Equity above. 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 each to entities owned and controlled by Messrs. Keating and Mallick in exchange for $500 total. 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 7. Capital Contribution and Partners’ Equity above.

 

Note 9. Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)

 

Aggregate Capitalized Costs and Costs Incurred

 

The aggregate amount of capitalized costs of oil, natural gas and NGL properties, including development, and related accumulated depreciation, depletion and amortization as of December 31, 2018 is as follows:

 

   

2018

 

Producing properties acquired

  $ 103,025,742  

Non-producing acquired

    68,481,176  

Development

    15,461,555  
      186,968,473  

Accumulated depreciation, depletion and amortization

    (4,889,806

)

Net capitalized costs

  $ 182,078,667  

 

70

 

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

 

The following unaudited information regarding the Partnership’s oil, natural gas and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

 

Proved oil and natural gas reserves are those quantities of oil, natural gas and NGLs which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

 

The independent consulting petroleum engineering firm of Pinnacle Energy of Oklahoma City, OK, prepared estimates of the Partnership’s oil, natural gas and NGL reserves as of December 31, 2018.

 

The Partnership’s net proved oil, NGL and natural gas reserves, all of which are located in the contiguous United States, as of December 31, 2018 have been estimated by the Partnership’s independent consulting petroleum engineering firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with SEC rules and regulations along with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

 

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate. Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available. “Revisions of previous estimates” in the table below represent changes in previous reserve estimates, either upward or downward, resulting from a change in economic factors, such as commodity prices, operating costs or development costs, or resulting from information obtained from the Partnership’s production history.

 

71

 

Net quantities of proved, developed and undeveloped oil, natural gas and NGL reserves are summarized as follows:

 

   

Proved Reserves

 
   

 

Oil 

(Bbls)

   

 

Natural Gas 

(Mcf)

   

 

NGLs 

(Bbls)

   

Total (BOE)

 

January 1, 2018

    -       -       -       -  

   Acquisition No. 1 (1)

    9,717,859       4,957,715       712,913       11,257,058  

   Acquisition No. 2 (2)

    10,298,392       4,779,497       696,600       11,791,575  

   Extensions, discoveries and other additions

    -       -       -       -  

   Revisions of previous estimates (3)

    653,770       545,023       124,901       869,507  

   Production (February 1, 2018 to December 31, 2018)

    (405,581

)

    (319,445

)

    (42,329

)

    (501,150

)

December 31, 2018

    20,264,440       9,962,790       1,492,085       23,416,990  

(1)

The Partnership acquired 11,257 MBOE of reserves attributable to producing developed wells and PUDs in conjunction with Acquisition No. 1 (see Note 3. Oil and Gas Investments).

(2)

The Partnership acquired 11,792 MBOE of reserves attributable to producing developed wells and PUDs in conjunction with Acquisition No. 2 (see Note 3. Oil and Gas Investments).

(3)

Revisions to previous estimates increased proved reserves by a net amount of 870 MBOE. These revisions result from 1,248 MBOE of upward adjustments attributable to changes in the future drill schedule and 7 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2018 to the drill schedules and oil, natural gas and NGL prices at the dates of Acquisitions No. 1 and No. 2, which were partially offset by 385 MBOE of downward adjustments related to well performance post acquisition-closing dates.

 

In accordance with SEC Regulation S-X, Rule 4-10, as amended, the Partnership uses the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2018 were $65.56 per barrel of oil and $3.10 per MMcf of natural gas, before price differentials. Including the effect of average price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2018 were $59.56 per barrel of oil, $2.43 per MMcf of natural gas and $20.25 per barrel of NGL.

 

   

Oil

   

Natural Gas

   

NGLs

         
   

(Bbls)

   

(Mcf)

   

(Bbls)

   

Total (BOE)

 

Proved developed reserves:

                               

   December 31, 2018

    6,982,216       4,126,780       686,765       8,356,778  
                                 

Proved undeveloped reserves:

                               

   December 31, 2018

    13,282,224       5,836,010       805,320       15,060,212  

 

The following details the changes in proved undeveloped reserves for 2018 (in BOE):

 

   

BOE

 

Proved undeveloped reserves, beginning

    -  

Proved undeveloped reserves acquired in Acquisition No. 1 (1)

    8,427,708  

Proved undeveloped reserves acquired in Acquisition No. 2 (2)

    7,279,846  

Revisions of previous estimates (3)

    1,252,630  

Conversion to proved developed reserves (4)

    (1,899,972

)

Proved undeveloped reserves, December 31, 2018

    15,060,212  

 

72

 


(1)

The Partnership acquired 8,428 MBOE attributable to PUDs in conjunction with Acquisition No. 1 (see Note 3. Oil and Gas Investments).

(2)

The Partnership acquired 7,280 MBOE attributable to PUDs in conjunction with Acquisition No. 2 (see Note 3. Oil and Gas Investments).

(3)

Revisions to previous estimates, from the respective closing dates for Acquisitions No. 1 and No. 2, increased PUDs by a net amount of 1,253 MBOE. These revisions result from 1,249 MBOE of upward adjustments attributable to changes in the future drill schedule and 4 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2018 to oil, natural gas and NGL prices at the dates of Acquisitions No. 1 and No. 2. There were no adjustments related to well performance.

(4)

Since the Partnership completed its first acquisition, 56 wells have either been completed or are in-process by the Partnership’s operators. This development has led to 1,900 MBOE of PUDs being converted to proved developed reserves from February 1, 2018 to December 31, 2018.

 

The Partnership anticipates all current PUD locations will be drilled and converted to PDP within five years of the date they were added. PUD locations and associated reserves which are no longer projected to be drilled within five years from the date they were first booked as proved undeveloped reserves have been removed as revisions at the time that determination was made.

 

Standardized Measure of Discounted Future Net Cash Flows

 

Accounting standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Partnership has followed these guidelines, which are briefly discussed below.

 

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year.

 

The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.

 

   

2018

 
   

(in thousands)

 
         

Future cash inflows

  $ 1,256,302  

Future production costs

    (342,615

)

Future development costs

    (102,210

)

Future net cash flows

    811,477  

10% annual discount

    (440,982

)

Standardized measure of discounted future net cash flows

  $ 370,495  

 

Changes in the standardized measure of discounted future net cash flows are as follows:

 

   

2018

 
   

(in thousands)

 

Standardized measure at beginning of period

  $ -  

Changes resulting from:

       

   Acquisition of reserves

    273,568  

   Sales of oil, natural gas and NGLs, net of production costs

    (17,733

)

   Net changes in prices and production costs

    71,883  

   Development costs incurred during the period

    15,462  

   Revisions to previous estimates

    11,491  

   Accretion of discount

    15,174  

   Change in estimated future development costs

    650  

Standardized measure of discounted future net cash flows

  $ 370,495  

 

73

 

Note 10.  Quarterly Financial Data (Unaudited)

 

The following is a summary of quarterly results of operations for the years ended December 31, 2018 and 2017. Net income (loss) per common unit is non-additive in comparison to net income (loss) per common unit for each year due to the timing and size of the Partnership’s common unit issuances.

 

   

2018 (1)

 
   

First Quarter

   

Second Quarter

   

Third Quarter

   

Fourth Quarter

 

Total revenue

  $ 3,497,079     $ 7,531,096     $ 5,503,706     $ 9,189,155  

Net income

  $ 1,288,325     $ 3,400,535     $ 2,087,725     $ 3,589,444  

Basic and diluted net income per common share

  $ 0.38     $ 0.82     $ 0.37     $ 0.51  

 

   

2017

 
   

First Quarter

   

Second Quarter

   

Third Quarter

   

Fourth Quarter

 

Total revenue

  $ -     $ -     $ -     $ -  

Net income (loss)

  $ (6,535

)

  $ (15,675

)

  $ 12,524     $ (500,561

)

Basic and diluted net income (loss) per common share

  $ -     $ -     $ 0.01     $ (0.18

)


(1)

The Partnership did not acquire its first operating asset until February 1, 2018.

 

Note 11.  Subsequent Events

 

In January 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 $5.1 million and proceeds net of selling and marketing costs of approximately $4.8 million.

 

In January 2019, the Partnership declared and paid $0.8 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

 

In February 2019, the Partnership closed on the issuance of approximately 0.2 million common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $4.4 million and proceeds net of selling and marketing costs of approximately $4.2 million.

 

In February 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 March 2019, the Partnership entered into additional costless collar derivative contracts to hedge a portion of the Partnership’s future oil and natural gas production for the period from April 2019 to September 2020. The contracts cover approximately 108,000 BOE of oil and natural gas production for the stated period. The Partnership did not pay or receive a premium related to the costless collar agreements.

 

In March 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 $6.9 million and proceeds net of selling and marketing costs of approximately $6.5 million.

 

In March 2019, the Partnership declared and paid $1.1 million, or $0.134247 per outstanding common unit, in distributions to its holders of common units.

 

74

 

Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

None

 

Item 9A.  Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

In accordance with Rules 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 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 of the General Partner concluded that the Partnership’s disclosure controls and procedures were effective as of December 31, 2018 to provide reasonable assurance that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Partnership’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.

 

Management’s Annual Report on Internal Control Over Financial Reporting

 

The Partnership’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act. The Partnership has performed an evaluation under the supervision and with the participation of its management, including the Chief Executive Officer and Chief Financial Officer of the General Partner, of the effectiveness of the Partnership’s internal control over financial reporting. The Partnership’s management assessed the effectiveness of its internal control over financial reporting as of December 31, 2018. The Partnership’s management used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) to perform its assessment. Based on this assessment, the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer of the General Partner, concluded, that as of December 31, 2018, the Partnership’s internal control over financial reporting was effective based on those criteria.

 

Changes in Internal Control Over Financial Reporting

 

There has been no change in the Partnership’s internal control over financial reporting during the quarter ended December 31, 2018 that has materially affected, or is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

 

Item 9B.  Other Information

 

None

 

75

 

PART III

 

Item 10.  Directors, Executive Officers, and Corporate Governance

 

Directors and Executive Officers of the General Partner

 

As is the case with many partnerships, the Partnership does not directly employ officers, directors or employees. Its operations and activities are managed by the Board of Directors and executive officers of the General Partner. References to the Partnership’s directors and executive officers are references to the directors and executive officers of the General Partner.

 

The following table sets forth the names, ages and offices of the present directors and executive officers of the General Partner as of December 31, 2018:

 

Name

 

Age

 

Position

Glade M. Knight

 

75

 

Director and Chief Executive Officer

David S. McKenney

 

56

 

Director and Chief Financial Officer and Secretary

 

The following is a biographical summary of the business experience of these directors and executive officers:

 

Glade M. Knight. Mr. Knight has been part owner of and the Chief Executive Officer of the General Partner since its formation in December 2016. Mr. Knight is also a part owner of and the Chief Executive Officer of Energy 11 GP, LLC, the general partner of Energy 11, a partnership also focused on investments in the oil and gas industry. Mr. Knight also is the founder and has served as Executive Chairman of Apple Hospitality REIT, Inc. since May 15, 2014, and previously served as Chairman and Chief Executive Officer. Mr. Knight was also the founder of Apple REIT Ten, Inc. and served as its Chairman and Chief Executive Officer from its inception until it merged with Apple Hospitality REIT, Inc. in September 2016. Mr. Knight was also the founder of Apple REIT Seven, Inc. and Apple REIT Eight, Inc. (which were real estate investment trusts) and served as the Chairman and Chief Executive Officer of those companies from their inception until the mergers with the Apple Hospitality REIT, Inc., which were completed in March 2014. In addition, Mr. Knight was the Chairman and Chief Executive Officer of Apple REIT Six, Inc., a real estate investment trust, from 2004 until the company merged with an affiliate of Blackstone Real Estate Partners VII in May 2013. Mr. Knight served in the same capacity for Apple Hospitality Five, Inc., another REIT, from 2002 until the company was sold to Inland American Real Estate Trust, Inc. in October 2007, and Apple Hospitality Two, Inc., a REIT, from 2001 until it was sold to an affiliate of ING Clarion in May 2007. In addition, Mr. Knight served as Chairman and Chief Executive Officer of Cornerstone Realty Income Trust, Inc. from 1993 until it merged with a subsidiary of Colonial Properties Trust in 2005. Following the merger in 2005 until April 2011, Mr. Knight served as a trustee of Colonial Properties Trust. Cornerstone Realty Income Trust, Inc. owned and operated apartment communities in Virginia, North Carolina, South Carolina, Georgia and Texas. Mr. Knight is the founding Chairman of Southern Virginia University in Buena Vista, Virginia. He also is a member of the Advisory Board to the Graduate School of Real Estate and Urban Land Development at Virginia Commonwealth University. Additionally, he serves on the National Advisory Council for Brigham Young University and is a founding member of the University’s Entrepreneurial Department of the Graduate School of Business Management. On February 12, 2014, Mr. Knight, Apple REIT Seven, Inc. (“Apple Seven”), Apple REIT Eight, Inc. (“Apple Eight”), Apple REIT Nine, Inc. (“Apple Nine”) and their related advisory companies entered into settlement agreements with the SEC. Along with Apple REIT Seven, Apple REIT Eight, Apple REIT Nine and their advisory companies, and without admitting or denying the SEC’s allegations, Mr. Knight consented to the entry of an administrative order, under which Mr. Knight and the noted companies each agreed to cease and desist from committing or causing any violations of Sections 13(a), 13(b)(2)(A), 13(b)(2)(B), 14(a), and 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Rules 12b-20, 13a-1, 13a-13, 13a-14, 14a-9, and 16a-3 thereunder.

 

David S. McKenney. Mr. McKenney has been part owner of and the Chief Financial Officer of the General Partner since its formation in December 2016. Mr. McKenney is also a part owner of and the Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, a partnership also focused on investments in the oil and gas industry. Mr. McKenney also serves as Senior Advisor for Apple Hospitality REIT, Inc., a real estate investment trust. Mr. McKenney was the President of Capital Markets of Apple REIT Ten, Inc. from its inception until it merged with Apple Hospitality REIT, Inc. in September 2016. Mr. McKenney previously served as President of Capital Markets for Apple Hospitality REIT, Inc. In addition, Mr. McKenney was the President of Capital Markets of Apple REIT Six, Inc., a real estate investment trust, from 2004 until the company merged with an affiliate of Blackstone Real Estate Partners VII in May 2013. Mr. McKenney served in the same capacity for Apple Hospitality Five, Inc., a lodging REIT, from 2002 until the company was sold to Inland American Real Estate Trust, Inc. in October of 2007, and Apple Hospitality Two, Inc., a lodging REIT, from 2001 until the company was sold to an affiliate of ING Clarion in May of 2007. From 1994 to 2001, Mr. McKenney served as Senior Vice President and Treasurer of Cornerstone Realty Income Trust, Inc., a REIT that owned and operated apartment communities in Virginia, North Carolina, South Carolina, Georgia and Texas. From 1992 to 1994, Mr. McKenney served as Chief Financial Officer for The Henry A. Long Company, a regional development firm located in Washington, D.C. From 1988 to 1992, Mr. McKenney served as a Controller at Bozzuto & Associates, a regional developer of apartments and condominiums in the Washington, D.C. area. Mr. McKenney holds Bachelor of Science degrees in Accounting and Management Information Systems from James Madison University.

 

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The General Partner

 

The General Partner is Energy Resources 12 GP, LLC, which was formed in 2016 and has no operating history. The General Partner was formed and is controlled by companies controlled by Glade M. Knight and David S. McKenney.

 

The General Partner receives a management fee for acting as general partner, as defined below. The Partnership has or will reimburse the General Partner for all third-party costs incurred and paid by the General Partner in connection with the formation of the Partnership, including third-party legal, accounting, printing, filing fees, travel and similar third party costs and expenses. In addition, the Partnership has or will reimburse the General Partner and its affiliates for all general and administrative expenses incurred by the General Partner and its affiliates in managing the Partnership’s business. These costs and expenses will include the direct and indirect costs and expenses of employee compensation, rental, office supplies, travel and entertainment, printing, legal, accounting, advertising, marketing and overhead. The beneficial owners of the General Partner will not be employees of the General Partner, and will not receive salary or other compensation from the General Partner or the Partnership other than the reimbursement of third-party costs and expenses, the management fee described below, and with respect to their equity interests in the Partnership.

 

 As described in the Prospectus, upon the Partnership’s first property acquisition, the Partnership is obligated to pay quarterly an annual management fee of 0.5% of the total gross equity proceeds raised in this offering to the General Partner. The fees and expenses paid to the General Partner are in exchange for:

 

 

Administering the day-to-day operations of the Partnership and performing or supervising the various administrative functions necessary to manage the Partnership;

 

Identifying producing and non-producing properties for potential acquisition, and evaluating, contracting for and acquiring these properties and managing the development of these properties; and

 

Monitoring or hiring a third party to monitor the operator(s) of the properties the Partnership acquires, including recommending whether the Partnership should participate in the development of such properties by the operators of the properties.

 

With the Partnership’s closing on the purchase of certain non-operated oil and gas properties in North Dakota on February 1, 2018, the Partnership began payment of the management fee at the end of the first quarter of 2018. Based upon the total gross equity proceeds raised from February 1, 2018 to December 31, 2018, the management fee paid to the General Partner for the year ended December 31, 2018 was approximately $537,000.

 

Code of Ethics

 

The General Partner has adopted a Code of Business Conduct and Ethics that applies to the executive officers of the General Partner and other persons performing services for the General Partner and the Partnership, generally. This Code of Business Conduct and Ethics is posted on the Partnership’s website at www.energyresources12.com.

 

Audit and Compensation Committee

 

The Partnership does not have a formal compensation committee and the Board of Directors of the General Partner serves as the audit committee. Because the Partnership does not have and is not seeking to list any securities on a national securities exchange or on an inter-dealer quotation system, the Partnership is not subject to a number of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, the Partnership is not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors. Accordingly, the Board of Directors has not made any determination as to whether any of the member of the Board of Directors would qualify as independent under the listing standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition. Additionally, for the same reason, the Partnership has not yet determined whether any of the directors is an audit committee financial expert.

 

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Item 11.  Executive Compensation

 

The Partnership does not directly employ any of the persons responsible for managing its business. Instead, the General Partner manages the Partnership’s day-to-day affairs and provides the Partnership with management and operating services. The members of the General Partner have been or will be reimbursed for documented out-of-pocket travel, entertainment and similar expenses incurred by them in connection with managing the Partnership’s business. The owners of the General Partner did not receive any salary, bonus or consulting fees for serving on the board of directors or for managing the Partnership’s business for the year ended December 31, 2018, other than through their ownership of the General Partner and the approximate $537,000 management fee paid to the General Partner by the Partnership in 2018. In addition, the members of the General Partner will not receive any salary, bonus or consulting fees for serving on the board of directors or for managing the Partnership’s business, other than the annual management fee of 0.5% of the total gross equity proceeds raised in the Partnership’s ongoing public offering (paid quarterly subsequent to the Partnership’s first property acquisition) and distributions in accordance with the incentive distribution rights and their ownership of common units, if any.

 

Outstanding Equity Awards at Fiscal Year-End

 

There were no outstanding equity awards for the Partnership’s named executive officers as of December 31, 2018, other than the Incentive Distribution Rights.

 

Compensation of Directors

 

The members of the General Partner do not receive compensation for their services as directors, aside from the management fee described in section “The General Partner” in Part III, Item 10 of this Form 10-K.

 

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

The following table sets forth as of March 29, 2019 the beneficial ownership of the common units that are owned by:

 

all persons who, to the knowledge of the management team, beneficially own more than 5% of the Partnership’s common units;

each executive officer of the General Partner; and

all current directors and executive officers of the General Partner as a group.

 

Name of Beneficial Owner

 

Common Units Beneficially Owned

   

Percentage of Common Units Beneficially Owned

 

Glade M. Knight

120 W. 3rd Street, Suite 220

Fort Worth, Texas 76102

    5,000       *  
                 

David S. McKenney

120 W. 3rd Street, Suite 220

Fort Worth, Texas 76102

    5,000       *  
                 

Directors and executive officers of the General Partner as a group

    10,000       *  

 

* Less than 1% of outstanding common units.

 

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Ownership of the General Partner

 

The General Partner is a limited liability company. The members of the General Partner and the membership interest owned are as follows:

 

GKOG, LLC, owns a 50% Class A (voting) membership interest in the General Partner. GKOG, LLC is a limited liability company wholly owned by Mr. Knight.

DMOG, LLC owns a 50% Class A (voting) membership interest in the General Partner. DMOG, LLC is a limited liability company wholly owned by Mr. McKenney and members of his immediate family.

CFK Energy, LLC owns a Class B (non-voting) membership interest in the General Partner. CFK Energy, LLC is a limited liability company wholly owned by Anthony F. Keating, III and members of his immediate family. Mr. Keating is the Co-COO of Energy 11 GP, LLC, the general partner of Energy 11, L.P.

Pope Energy Investors, LP owns a Class B (non-voting) membership interest in the General Partner. Pope Energy Investors, LP is a limited partnership wholly owned by Mr. Mallick and members of his immediate family. Mr. Mallick is the Co-COO of Energy 11 GP, LLC, the general partner of Energy 11, L.P.

 

Each Class A member of the General Partner has the right to appoint one person to the General Partner’s Board of Directors. All decisions regarding the business of the General Partner and the Partnership will be made by the Board of Directors of the General Partner at meetings of the Board of Directors at which a quorum is present. The presence of a majority of the directors constitutes a quorum, and the vote of a majority of a quorum constitutes a decision by the Board of Directors.

 

General Partner Class A Units

 

The owners of the members of the General Partner have granted each other the right of first refusal to acquire any interests in the members of the General Partner that the owners propose to sell. If the owners of the members of the General Partner do not exercise the right of first refusal, the purchaser of the owner of the General Partner will have the right to appoint a member to the board of directors, and if a person or group of affiliated persons were to acquire a controlling interest in both of the owners of the General Partner, the person would be able to control the General Partner and the Partnership. The Partnership Agreement does not give the holders of common units the right to cause an owner of the General Partner to exercise its buy-sell right, or provide the holders the right to consent to or otherwise approve the transfer by an owner of the General Partner of its membership interest in the General Partner. The General Partner does, however, agree not to permit a change of control of the General Partner to occur. A change of control is defined as a person who is not currently a beneficial owner of the General Partner or a “qualifying owner” becoming the beneficial owner of 50% or more of the membership interest in the General Partner. A qualifying owner generally is defined as the following with respect to the current beneficial owners of the General Partner: conservators, guardians, executors, administrators, and similar persons of any trust, private foundation or custodianship that such beneficial owner, his spouse, lineal descendants or estate is a beneficiary.

 

General Partner Class B Units

 

In November 2017 and June 2018, the Partnership engaged Regional Energy Investors, LP (“REI”) to perform advisory and consulting services, including supporting the Partnership through closing, financing and post-closing on its two 2018 acquisitions of oil and gas assets in North Dakota (the “Bakken Assets”). Under the advisory and administration agreements (the “Agreements”), REI was 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 were available after Payout, to the holders of the Partnership’s common units.

 

On December 28, 2018, the Partnership terminated its 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 are paid, as defined in Note 7. Capital Contributions and Partners’ Equity of Part II, Item 8 of this Form 10-K.

 

The General Partner continues to be controlled and managed by and the Class A voting units of the General Partner are owned by entities controlled by Messrs. Knight and McKenney, the Chief Executive Officer and Chief Financial Officer, respectively, of the General Partner. CFK Energy, LLC is owned by an entity that is controlled by Anthony F. Keating, III, Co-Chief Operating Officer of Energy 11 GP, LLC, and Pope Energy Investors, LP is owned by an entity that is controlled by Michael J. Mallick, Co-Chief Operating Officer of Energy 11 GP, LLC. Energy 11 GP, LLC is the general partner of Energy 11, L.P. REI is also owned by entities that are controlled by Messrs. Keating and Mallick.

 

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Securities Authorized for Issuance under Equity Compensation Plans

 

The Partnership does not have any equity compensation plans.

 

Item 13.  Certain Relationships and Related Transactions, and Director Independence

 

Reimbursement of Expenses to General Partner in Connection with Offering Costs

 

The Partnership Agreement provides that the General Partner is entitled to be reimbursed out of capital contributions for offering and organization costs paid to third parties, including legal, accounting, engineering, printing and filing fees.

 

Reimbursement of Expenses to General Partner in Connection with Operations of the Partnership

 

The Partnership has or will reimburse the General Partner and the General Partner’s affiliates for their General and administrative costs allocable to the Partnership. These expenses will include compensation expense, rent, travel, and other general and administrative and overhead expenses. Currently, the only business of the General Partner is to act as General Partner of the Partnership, and all of the General Partner’s general and administrative costs will be paid by the Partnership. If affiliates of the General Partner form other partnerships or engage in other oil and gas activities, the General Partner will allocate its general and administrative costs to the Partnership and other partnerships or businesses in a manner deemed reasonable by the General Partner.

 

During the years ended December 31, 2018 and 2017, approximately $402,000 and $57,000 of related party costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership in connection with its operations. At December 31, 2018, approximately $135,000 was due to a member of the General Partner.

 

Management Fee

 

The Partnership has 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 Partnership 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 December 31, 2018, the management fee paid to the General Partner for the year ended December 31, 2018 was approximately $537,000.

 

Incentive Distribution Rights

 

On the initial closing date, the Partnership issued incentive distribution rights, which are non-voting limited partner interests that entitle the holder of such rights, after Payout occurs, to 30% of all amounts distributed until the Managing Dealer receives 4% of the gross proceeds of the common units sold, and to 60% of all amounts distributed thereafter, to the General Partner.

 

Cost Sharing Agreement

 

The Chief Executive Officer and Chief Financial Officer of the Partnership’s General Partner are also the Chief Executive Officer and Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, L.P. (“Energy 11”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11 to provide access to Energy 11’s personnel and administrative resources. The personnel provide accounting, asset management and other day-to-day management support for the Partnership. 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 for Energy 11. The agreement may be terminated at any time by either party upon 60 days written notice. The officers and members of the Partnership’s General Partner are also officers and members of the general partner of Energy 11. For the year ended December 31, 2018, approximately $252,000 of expenses subject to the cost sharing agreement were incurred by the Partnership and have been or will be reimbursed to Energy 11. At December 31, 2018, approximately $77,000 was due from the Partnership to Energy 11.

 

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Advance from member of General Partner

 

In January 2018, the Partnership received an advance of $7.0 million from a member of the General Partner to partially fund the Partnership’s first acquisition of North Dakota assets. The Partnership repaid a member of the General Partner in full in May 2018. The advance did not bear interest and the member of the General Partner did not receive any compensation for the advance.

 

Debt guarantees

 

The Chief Executive Officer and Chief Financial Officer of the Partnership’s General Partner had guaranteed repayment of the Partnership’s term loan to partially fund the Partnership’s first acquisition of North Dakota Assets. In addition, the Chief Executive Officer and Chief Financial Officer had guaranteed repayment of the Partnership’s 2017 unsecured line of credit used to fund some of the Partnership’s offering and operating costs. Both facilities were agreements with Bank of America. Neither the Chief Executive Officer nor the Chief Financial Officer received any consideration in exchange for providing the guarantee on either loan.

 

Regional Energy Investors, LP

 

In November 2017 and June 2018, the Partnership engaged Regional Energy Investors, LP (“REI”) to perform advisory and consulting services, including supporting the Partnership through closing, financing and post-closing on its two 2018 acquisitions of oil and gas assets in North Dakota (the “Bakken Assets”). Under the advisory and administration agreements (the “Agreements”), the Partnership paid REI a total of approximately $9.4 million in 2018. In addition, REI was 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 were available after Payout, to the holders of the Partnership’s common units.

 

On December 28, 2018, the Partnership terminated its 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 are paid, as defined in Note 7. Capital Contributions and Partners’ Equity of Part II, Item 8 of this Form 10-K.

 

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. In addition, CFK Energy, LLC and Pope Energy Investors, LP are owned by entities controlled by Messrs. Keating and Mallick, respectively.

 

Director Independence

 

Because the Partnership does not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, the Partnership is not required to have a board of directors comprised of a majority of independent directors under SEC rules or any listing standards. Accordingly, the Board of Directors of the General Partner has not made any determination as to whether any non-employee directors satisfy any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition.

 

81

 

Item 14.  Principal Accountant Fees and Services

 

Ernst & Young LLP (“EY”), as the Partnership’s independent registered public accounting firm, has audited the Partnership’s consolidated financial statements for the most recent fiscal year ended December 31, 2018. EY was selected and appointed as the Partnership’s independent registered public accounting firm in 2017.

 

For the fiscal years ended December 31, 2018 and 2017, fees paid or payable to EY for services performed in connection with the audit of the 2018 financial statements, the audit of the 2017 financial statements, reviews of S-1s and any amendments, SEC comment letters, acquisition audits, issuance of consents and 2018 and 2017 interim reviews are as follows:

 

   

Year Ended December 31, 2018

   

Year Ended December 31, 2017

 
                 

Audit fees

  $ 232,000     $ 145,000  

Audit-related fees

    103,300       40,000  

Tax fees

           

All other fees

           

Total

  $ 335,300     $ 185,000  

 

Pre-Approval Policies and Procedures

 

The General Partner currently has no Board committees. The Board of Directors has adopted policies regarding the pre-approval of auditor services. Specifically, the Board of Directors approves all services provided by the independent public accountants and reviews the actual and budgeted fees for the independent public accountants periodically at regularly scheduled meetings. All of the services provided by EY during the years ended December 31, 2018 and 2017 were approved by the Board of Directors.

 

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PART IV

 

Item 15.  Exhibits and Financial Statement Schedules

 

(a) Documents filed as part of this report:

 

1. Financial Statements:

 

 

(i) Report of Independent Registered Public Accounting Firm – Ernst & Young LLP

 

 

(ii) Balance Sheets as of December 31, 2018 and December 31, 2017

 

 

(iii) Statements of Operations for the years ended December 31, 2018 and 2017

 

 

(iv) Consolidated Statements of Partners’ Equity for the years ended December 31, 2018 and 2017

 

 

(v) Consolidated Statements of Cash Flows for the years ended December 31, 2018 and 2017

 

 

(vi) Notes to Consolidated Financial Statements

 

2. Financial Statement Schedules:

 

 

(i) All schedules are omitted as they are not applicable, not required or the required information is included in the consolidated financial statements or notes thereto.

 

 

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3. Exhibits:

 

The following exhibits are included, or incorporated by reference, in this Annual Report on Form 10-K, for the year ended December 31, 2018 (and are numbered in accordance with Item 601 of Regulation S-K). Exhibits incorporated by reference to this Form 10-K as listed below are available at www.sec.gov.

 

Exhibit No.

 

Description

 

 

 

1.1

 

Exclusive Dealer Manager Agreement with David Lerner Associates, Inc. (incorporated by reference from Exhibit 1.1 to Pre-Effective Amendment No. 1 to the Partnership’s Registration Statement on Form S-1 filed on April 18, 2017).

2.1

 

Purchase and Sale Agreement dated November 21, 2017 by and between Energy Resources 12 Operating Company, LLC, as Purchaser, and Bruin E&P Non-Op Holdings, LLC, as Seller (incorporated by reference from Exhibit 2.1 to the Partnership’s Current Report on Form 8-K filed on November 22, 2017).

2.2

 

Purchase and Sale Agreement dated June 29, 2018 by and between Energy Resources 12 Operating Company, LLC, as Purchaser, and Bruin E&P Non-Op Holdings, LLC, as Seller (incorporated by reference from Exhibit 2.1 to the Partnership’s Current Report on Form 8-K filed on July 6, 2018).

3.1

 

Certificate of limited partnership of Energy Resources 12, L.P. (incorporated by reference from Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 filed on March 23, 2017).

3.2

 

First Amended and Restated Limited Partnership Agreement of Energy Resources 12, L.P. (incorporated by reference from Exhibit A to the Prospectus included as part of Post-Effective Amendment No. 1 to the Partnership’s Registration Statement on Form S-1 filed on February 1, 2018).

10.1

 

Form of Subscription Agreement (incorporated by reference from Exhibit B to the Prospectus included as part of Post-Effective Amendment No. 1 to the Partnership’s Registration Statement on Form S-1 filed on February 1, 2018).

10.2

 

Advisory and Administration Agreement dated November 21, 2017 by and between Energy Resources 12 Operating Company, LLC, Energy Resources 12, L.P., and Regional Energy Investors, LP (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on November 22, 2017).

10.3

 

Loan Agreement between Bank of America, N.A. and Energy Resources 12, L.P. dated January 16, 2018 (incorporated by reference from Exhibit 10.1 to the Partnership’s form 8-K filed on January 17, 2018).

10.4

 

Cost Sharing Agreement between Energy Resources 12, L.P., Energy 11, L.P. and Energy 11 Management, LLC, dated January 31, 2018 (incorporated by reference from Exhibit 10.7 to Post-Effective Amendment No. 1 to the Partnership’s Registration Statement on Form S-1 filed on February 1, 2018).

10.5

 

Advisory and Administration Agreement dated June 29, 2018 by and between Energy Resources 12 Operating Company, LLC, Energy Resources 12, L.P., and Regional Energy Investors, LP (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on July 6, 2018).

10.6

 

Revolver Loan Agreement dated as of August 31, 2018 between and among Energy Resources 12, L.P. and Energy Resources 12 Operating Company, LLC, collectively, the Borrower, and Simmons Bank, as Administrative Agent and Letter of Credit Issuer and the Lenders Signatory Party Hereto, collectively, the Lenders (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on September 5, 2018).

10.7

 

Loan Agreement Amendment and Consent, made as of August 16, 2018, between Bank of America, N.A. and Energy Resources 12, L.P. (incorporated by reference from Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed on September 5, 2018).

10.8

 

Termination of Advisory and Administration Agreement dated effective November 21, 2017 and Termination of Advisory and Administration Agreement dated effective June 29, 2018 (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on December 28, 2018).

10.9

 

First Amendment to Revolver Loan Agreement dated December 27, 2018 between and among Energy Resources 12, L.P. and Energy Resources 12 Operating Company, LLC, collectively, the Borrower, and Simmons Bank, as Administrative Agent and Letter of Credit Issuer and the Lenders Signatory Party thereto Revolver Loan Agreement dated August 31, 2018, collectively, the Lenders.*

 

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21.1

 

Subsidiaries of the Partnership*

23.1   Consent of Ernst & Young LLP*
23.2   Consent of Pinnacle Energy Services, LLC*

31.1

 

Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*

31.2

 

Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*

32.1

 

Certification of Chief Executive Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*

32.2

 

Certification of Chief Financial Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*

99.1

 

Report of Pinnacle Energy Services, LLC, Independent Petroleum Consultants.*

101

 

The following materials from Energy Resources 12, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2018 formatted in XBRL (eXtensible Business Reporting Language): (i) the Balance Sheets, (ii) the Statements of Operations, (iii) the Statement of Cash Flows, and (iv) related notes to these financial statements, tagged as blocks of text and in detail*

 

*Filed herewith.

 

Item 16.  Form 10-K Summary

 

None

 

 

 

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SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

ENERGY RESOURCES 12, L.P.

 

By: Energy Resources 12 GP, LLC, its General Partner

 

 

By:

/s/ David S. McKenney

 

 

 

David S. McKenney

 

 

Chief Financial Officer

 

Date: March 29, 2019

 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature

 

Title with General Partner

 

Date

 

 

 

 

 

/s/ Glade M. Knight

 

Director, Chief Executive Officer

 

March 29, 2019

Glade M. Knight

 

(principal executive officer)

 

 

 

 

 

 

 

/s/ David S. McKenney

 

Director, Chief Financial Officer

 

March 29, 2019

David S. McKenney

 

(principal financial and accounting officer)

 

 

 

 

 

 

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