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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

 

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

 

For the fiscal year ended: December 31, 2016

 

OR

 

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

 

COMMISSION FILE NUMBER: 000-55615

 

(Exact name of Registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code: (817) 882-9192

 

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 and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐

 

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

 

 

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

 

There is no established public market for the registrant’s outstanding limited partnership interests. The registrant is continuing to conduct the ongoing initial public offering of its limited partnership interests (the “public offering”) pursuant to its registration statement on Form S-1 (File No. 333-197476) at a per unit price of $20.  The aggregate market value of the registrant’s limited partnership interests held by non-affiliates of the registrant as of June 30, 2016 was $0.

As of March 3, 2017, the Partnership had 16,690,442 common units outstanding. 

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ENERGY 11, L.P.

FORM 10-K

Index

 

 

 

 

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:

 

 

These forward-looking statements reflect our 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 our 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:

 

 

Although we believe the expectations reflected in such forward-looking statements are based upon reasonable assumptions, we cannot assure investors that our 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, we undertake 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

Energy 11, L.P. (the “Partnership,” “we” or “us”) was formed as a Delaware limited partnership in June 2013.  The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013.  In the public offering, we are offering common units of limited partners’ interests (the “common units”) on a best-efforts basis with the intention of raising up to $2,000,000,000 of capital, consisting of 100,263,158 common units. The registration statement with respect to the public

offering was declared effective by the Securities and Exchange Commission (“SEC”) on January 22, 2015.  As of August 19, 2015, we completed the sale of the minimum offering of 1,315,790 common units. The subscribers 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, 2016, the Partnership had sold 14.6 million common units for gross proceeds of $286.4 million and proceeds net of offering costs of $267.1 million. The offering will expire on the sooner of April 24, 2017 or the sale of 100,263,158 common units. As of March 3, 2017, we had 16,690,442 common units outstanding. 

As of December 31, 2016, we own an approximate 11% working interest in approximately 216 existing producing wells and approximately 257 future development locations in the Sanish field located in Mountrail County, North Dakota (the “Sanish Field Assets”). The Sanish Field Assets are part of the Bakken shale formation in the Greater Williston Basin. On January 11, 2017, the Partnership completed the purchase of an additional 11% working interest in the Sanish Field Assets. All of our Sanish Field Assets are operated by Whiting Petroleum Corporation (“Whiting”) (NYSE:WLL), a publicly traded oil and gas company.

The general partner of the Partnership is Energy 11 GP, LLC (the “General Partner”).

 

Business Objective

Our primary investment objectives are to (i) acquire producing and non-producing oil and gas properties with development potential, 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 – 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 used to acquire a 22-23% working interest in the Sanish Field Assets and will be used to further develop these assets.

We were formed to acquire and develop oil and gas properties located onshore in the United States.  We will manage and further develop our existing interests and as capital is available will look for additional interests in oil and gas properties.

Our Oil and Natural Gas Reserves

 

The table below summarizes our estimated net proved reserves as of December 31, 2016:

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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, we 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 our control. Prices for oil or natural gas at December 31, 2016 are above the average calculated for 2016. Sustained higher prices will have a positive impact to the estimated quantities and present values of our reserves; however, should prices decline, the estimated quantities and present values of our reserves will be reduced.

Current Developments

2017 Acquisition

As discussed above, the purchase of the additional 11% working interest in the Sanish Field Assets was completed on January 11, 2017. The purchase price was $130.0 million and was funded by the Partnership with $90.0 million in cash (from the sale of the Partnership’s common units in its ongoing, best-efforts offering) and a $40.0 million promissory note (“Seller Note”). The Partnership paid the $40.0 million Seller Note in full on February 23, 2017.  The Seller Note bore interest at 5% per annum up to the payoff date.

 

Management Agreement

 

At the initial closing of the sale of common units on August 19, 2015, the Partnership entered into a management services agreement (the “Management Agreement”) with E11 Management LLC (the “Former Manager”) to provide management and operating services regarding substantially all aspects of the Partnership. Under the Management Agreement, the Former Manager agreed to provide management and operating services to the Partnership in exchange for a monthly fee. In addition, the Partnership issued 100,000 Class B units to an affiliate of the Former Manager upon entering into the Management Agreement. The Class B units entitle the holder to receive a portion of distributions made after Payout, as defined in Distributions below.

 

The Former Manager was formed by Aubrey K. McClendon. The Management Agreement was terminable by the Partnership if, among other reasons, Mr. McClendon, the Former Manager’s key employee, ceased to be employed by the Former Manager and the Partnership did not approve of a proposed replacement of such key employee. On March 2, 2016, Mr. McClendon died in a car accident. Following Mr. McClendon’s death and subsequent correspondence between the Former Manager and the Partnership, on April 5, 2016, the Partnership elected not to approve a replacement key employee for Mr. McClendon and exercised its right to terminate the Management Agreement. Accordingly, the fees under the Management Agreement were no longer accrued as of the effective date of termination. Also, upon termination of the Management Agreement and in accordance with the terms therewith, 37.5% of the Class B units owned by Incentive Holdings were canceled. As of December 31, 2016, the Class B units owned by Incentive Holdings totaled 62,500. Since substantially all the Partnership’s properties are operated by Whiting and the Partnership only owns a non-operating working interest in the Sanish Field Assets, most of the services that the Former Manager had been contracted to perform are being performed by Whiting. Consequently, the termination of the Management Agreement has not had and the Partnership does not anticipate that the termination will have an adverse effect on its operations.

 

See further discussion in Note 6 titled “Management Agreement” In Part II, Item 8 of this Form 10-K.

 

Related Parties

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

Partners’ Equity and Distributions

As of December 31, 2016, the Partnership had sold 14.6 million common units for gross proceeds of $286.4 million and proceeds net of offering costs of $267.1 million. David Lerner Associates, Inc. is the dealer manager for the Partnership’s best-efforts offering (the “Dealer Manager”). Under the agreement with the Dealer Manager, the Dealer Manager receives a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, 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.

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 (owned by the General Partner), with respect to Class B units or the contingent, incentive payments to the Dealer Manager, until Payout occurs.

The Partnership Agreement provides that Payout 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:

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First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000; (iii) to the Dealer Manager, as the contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any, to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the contingent incentive fee under the Dealer Manager Agreement;

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Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000; (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest.

 

year ended December 31, 2016 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.

 

Our controls over reserve estimates include engaging Pinnacle Energy as our independent petroleum engineer. We provided information about our oil and natural gas properties, including production profiles, prices and costs, to Pinnacle Energy and they prepared estimates of our reserves attributable to our 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.

 

Our President works closely with our independent engineers, 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. Our President 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 our General Partner also meets with our President to discuss matters and policies related to our reserves.

 

 Our 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.

 

We apply and maintain internal controls, including but not limited to the following, to ensure the reliability of reserves estimations:

		MBOE
Proved undeveloped reserves, December 31, 2015			4,988
Revisions of previous estimates			442
Conversion to proved developed reserves			-
Proved undeveloped reserves acquired			-
Proved undeveloped reserves, December 31, 2016			5,430

be available for development of our PUDs, which may cause us to decrease the number of our PUDs we expect to develop within the five year time frame. In addition, lower oil and natural gas prices may cause our PUDs to become uneconomic to develop, which would cause us to remove them from the proved undeveloped category. 

   

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 our sale of oil, natural gas, and natural gas liquids for the periods indicated below.

 

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(1) All production and cost figures are derived from the Partnership’s ownership of the properties from December 18, 2015 through December 31, 2015.

 

Delivery Commitments

 

As of December 31, 2016, we had no commitments to provide a fixed quantity of oil or natural gas.

 

		December 31, 2016
		Gross				Net
Oil wells:
Sanish Field			216				23.1

Developed and Undeveloped Acreage Position

 

The following table sets forth information with respect to our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2016, all of which is located in the State of North Dakota in the United States:

 

 

As is customary in the oil and natural gas industry, we 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 we have an interest are for varying primary terms and, if production under a lease continues from developed lease acreage beyond the primary term, we are 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.

 

Marketing and Customers

 

The market for our oil and natural gas production depends on factors beyond our 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.

 

Whiting, as operator of our properties, sells 99% of our production on our behalf.

 

Title to Properties

 

As is customary in our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that our 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 our operations. The interests owned by us 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 our operations.

 

Insurance

 

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to our oil and gas properties, control of well, auto liability, marine liability, worker’s compensation and employer’s liability, among other things. Since we are not the operator of any of our properties, we rely on the insurance of the operator of our properties, of which our share of the cost is allocated back to the Partnership through the Joint Operating Agreement.

Currently, we have general liability insurance coverage up to $1,000,000 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain excess liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached.

 

We re-evaluate 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 we will be able to maintain insurance in the future at rates that we consider reasonable and we 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.  We 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 ours.  As a result, our 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 our financial or other resources will permit.

 

We 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.  We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

 

Seasonal Nature of Business

 

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas where we may acquire producing properties.  These seasonal anomalies can pose challenges for meeting our drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increased costs or delay our 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.

 

Environmental, Health and Safety Matters and Regulation

such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our 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.

 

The following is a summary of some of the existing laws, rules and regulations to which our 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, we expect to generate waste as a routine part of our operations that may be subject to RCRA.  Although a substantial amount of the waste expected to be generated in our operations 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.  Any such change could result in substantial costs to manage and dispose of waste, which could have a material adverse effect on our 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.

 

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our expected operations, our properties may 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.  We may also be the owner of sites on which hazardous substances have been released.  If contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.  Further, we could be required to suspend or cease operations in contaminated areas.

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. 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, we 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.

 

Safe Drinking Water Act and Hydraulic Fracturing

 

Many of the properties we own and expect to acquire 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).

 

Congress has repeatedly 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.  Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies.  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.

 

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. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities.  The EPA completed a wide-ranging study on the effects of hydraulic fracturing on drinking water resources and released its results in 2016. The EPA indicated that uncertainties and data gaps limited the EPA’s ability to fully assess impacts to drinking water resources locally and nationally, but hydraulic fracturing can impact drinking water under certain circumstances.

 

If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where we own properties that require additional drilling, we could incur substantial compliance costs and such requirements could adversely delay or restrict our ability to conduct fracturing activities on our assets.

 

 

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 we own, we may be liable for costs and damages.

 

Air Emissions

 

Our operations 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 us 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 require 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 received numerous requests for reconsideration of these rules, and court challenges to the rules were also filed.  The EPA has expressed an intent to issue some revisions that are likely responsive to some of the requests.  For example, in September 2013, the EPA promulgated amendments related to certain storage vessels and in July 2014 proposed amendments related to well completion actions and to remove affirmative defense provisions.  These rules and any revised rules may require the installation of equipment to control emissions on producing properties we acquire.

 

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 us 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 recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations.  Those measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources, the proposal of which is discussed above.

 

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.

 

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. Some members of Congress have expressed the intention to promote legislation to curb the EPA’s authority to regulate GHGs. 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 our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors. 

Endangered Species Act

 

The Endangered Species Act 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.  We 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 our 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 we acquire.  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 is 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 we might conduct operations could result in limitations or prohibitions on our activities and could adversely impact the value of our leases.

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 our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us 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.

 

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. Our drilling and production operations 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 we operate 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 our 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.

 

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.  We qualify 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 our common unitholders 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.

 

Federal Natural Gas Regulation

 

The availability, terms and cost of transportation 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, or FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. 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.

 

Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis. FERC has announced several important transportation related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

 

FERC has also issued several other generally pro–competitive policy statements and initiatives affecting rates and other aspects of pipeline transportation of natural gas. On May 31, 2005, FERC generally reaffirmed its policy of allowing interstate pipelines to selectively discount their rates in order to meet competition from other interstate pipelines. On June 15, 2006, FERC issued an order in which it declined to establish uniform standards for natural gas quality and interchangeability, opting instead for a pipeline–by–pipeline approach. On June 19, 2006, in order to facilitate development of new storage capacity, FERC established criteria to allow providers to charge market–based (i.e., negotiated) rates for storage services. On June 19, 2008, the FERC removed the rate ceiling on short–term releases by shippers of interstate pipeline transportation capacity.

The U.S. Department of Energy (“DOE”) regulates the export of natural gas produced in the U.S., including the export of liquefied natural gas (“LNG”), and the FERC regulates the construction and operation of liquefaction facilities used to convert gaseous natural gas into liquid for export as LNG. The DOE has granted several long-term LNG export licenses and FERC has authorized the construction and operation of several LNG export facilities for natural gas produced in the lower 48 States of the U.S., several of which are currently under construction. Beginning in 2016, cargo of LNG from the lower 48 States of the U.S. is being exported. It is too early to tell what impact this expansion of the markets available to natural gas produced in the U.S. will have on U.S. natural gas prices.

 

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. We do not believe that compliance with these laws will have a material adverse effect upon our operations.

Employees

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 will be made by the board of directors of the General Partner and its officers.

General Corporate Information

 

Energy 11, LP is a Delaware limited partnership founded in 2013 with principal offices at 120 W 3rd Street, Suite 220, Fort Worth, Texas 76102. We can be reached at (817) 882-9192 and our website address is www.energyeleven.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.

 

 

On December 18, 2015, the Partnership acquired the Sanish Field Assets and in January 2017, the Partnership acquired additional working interests in the Sanish Field Assets. We have not selected any other properties for acquisition by the Partnership and may not select additional properties for acquisition until after you invest in the Partnership. You may not have an opportunity before purchasing units to evaluate geophysical, geological, economic or other pertinent information regarding any additional prospects to be selected. If we select additional properties for acquisition by the Partnership during the offering period, we will file a prospectus supplement describing the properties and their proposed acquisition. If you subscribe for units prior to any such supplement you will not be permitted to withdraw your subscription as a result of the selection of any property.

 

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.

 

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 our 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.

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

 

Our General Partner has the right to make distributions from the proceeds of borrowings and capital contributions. It is likely that all or a part of distributions to common unitholders during the early years of our operations will represent the proceeds of capital contributions, rather than cash generated in our operations. This is because as proceeds are raised in the public offering, it is not always possible immediately to invest them in oil and gas properties that generate our desired return on investment. There may be a “lag” or delay between the raising of offering proceeds and their investment in oil and gas properties. Investors who acquire common units relatively early in our public offering, as compared with later investors, may receive a greater return of offering proceeds as part of the earlier distributions. 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, we expect 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 oil and gas properties and will reduce the amount of distributions we may make in the future. We cannot and do not guarantee that investors will receive any specific return on their investment. Further, there is no limitation on the amount of distributions that can be funded from offering proceeds or indebtedness. Because cash generated from our operations will be comingled and is fungible with cash received from capital contributions and indebtedness, we are unable to determine a point in time when distributions will no longer be sourced from capital contributions.

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.

 

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

 

The General Partner will be subject to conflicts of interest in operating our business.  These conflicts include:

 

·

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

·

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

·

Conflicts caused by competition for management time and attention with other oil and gas partnerships and with other business activities in which management of our General Partner are or may be involved.

Our Partnership Agreement provides that our 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, our 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 our 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.

 

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

 

The General Partner and its affiliates will receive reimbursement of third-party costs incurred in connection with the formation of the Partnership and the Partnership’s business activities and will be reimbursed for general and administrative costs of the General Partner allocable to the Partnership as described in “Compensation” within the Partnership’s prospectus, 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.

 

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.

 

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

 

Beginning five to seven years after the termination of the Partnership’s public offering, we plan either to sell our properties and distribute the proceeds of the sale, after payment of liabilities and expenses, to our partners, merge with another entity, or list the common units on a national securities exchange. The decision to sell our properties or merge with another entity will be based on a number of factors, including the domestic and foreign supply of and demand for oil, natural gas and other hydrocarbons, commodity prices, demand for oil and natural gas assets in general, the value of our assets, the projected amount of our oil and gas reserves, general economic conditions and other factors that are out of our control. In addition, the ability to list our common units on a national securities exchange will depend on a number of factors, including the state of the U.S. securities markets, our ability to meet the listing requirements of national securities exchanges, securities laws and regulations and other factors. If we are unable to either sell our properties, merge or list the common units on a national securities exchange in accordance with our current plans, you may be unable to sell or otherwise transfer your common units and you may lose some or all of your investment.

The Partnership was required to receive minimum offering proceeds of $25,000,000 to break escrow, and the Partnership’s maximum offering proceeds may not exceed $2,000,000,000. The minimum offering was reached on August 19, 2015 and the offering expires in April 2017. 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. As of January 31, 2017, all of the Partnership’s investments are in the Sanish Field Assets.

 

We may have indebtedness under a credit facility. Restrictions in a credit facility may limit our ability to make distributions to holders of our common units and may limit our ability to capitalize on acquisitions and other business opportunities.

 

We expect that any credit facility we are able to negotiate will contain covenants limiting our 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 us to maintain certain financial ratios and tests.  In addition, the borrowing base under our anticipated facility will be subject to periodic review by our lenders.  Difficulties in the credit markets may cause the banks to be more restrictive when redetermining our borrowing base.

Our General Partner has sole responsibility for conducting our business and managing our operations.  Our 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 our common units.

 

Conflicts of interest may arise between our General Partner, Energy 11 GP, LLC, and its respective affiliates on the one hand, and us and the holders of our common units, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of its owners over the interests of holders of our common units.  These conflicts include, among others, the following situations:

 

·

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

·

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

·

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

·

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

 

Your liability may not be limited if a court finds that common unitholder action constitutes control of our 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.  Our Partnership is organized under Delaware law and we plan 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 we may do business.  You could be liable for any and all of our obligations as if you were a general partner if:

 

·

a court or government agency determined that we 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 our Partnership Agreement or to take other actions under our Partnership Agreement constitutes “control” of our business.

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, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our 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.

 

We will need additional funding for the Sanish Field Assets in order to retain our full interest therein.

 

We anticipate that we will be obligated to significantly invest in drilling capital expenditures within the next five years to retain our working interest in the Sanish Field Assets without becoming subject to non-consent penalties under the joint operating agreements governing those properties.  We will depend, at least in part, on continued sales pursuant to the terms of this Offering, increased cash flow from operations and possibly indebtedness to fund the anticipated capital expenditures needed to retain our full interest in these assets. None of these funding sources is guaranteed, and if we are unable to obtain all of this funding we may lose all or a portion of the assets acquired, and our results of operations will be negatively affected accordingly.

 

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

 

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

·

the amount of oil, natural gas and natural gas liquids we produce;

·

the prices at which we sell our production;

·

our ability to hedge commodity prices at economically attractive prices;

·

the level of our capital expenditures;

·

the level of our operating and administrative costs including reimbursement to our General Partner; and

·

the level of our interest expense, which depends on the amount of any future indebtedness and the interest payable thereon.

 

 

·

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

·

overall domestic and global economic conditions;

·

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, 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;

·

technological advances affecting energy production and consumption;

·

domestic and foreign governmental regulations and taxation;

·

the impact of energy conservation efforts;

·

the proximity and capacity of oil, natural gas and other hydrocarbon pipelines and other transportation facilities to our production;

·

speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;

·

price and availability of competitors’ supplies of oil and natural gas; and

·

the price and availability of alternative fuels.

 

Low oil, natural gas and other hydrocarbon prices will decrease our revenues, but may also reduce the amount of oil, natural gas or other hydrocarbons that we can economically produce. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non–cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our 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. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under any credit facility, which may adversely affect our ability to make cash distributions to holders of our common units and service our debt obligations.

 

potential tax and ERISA liabilities, and other liabilities and similar factors.  Reserve estimates may be prepared internally by us or by a third party. 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.  We expect that our review efforts will be focused on the higher valued properties in our acquisitions and will be inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition.  Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential.  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 our financial condition and results of operations and our ability to make cash distributions to holders of our common units.

 

Additional potential risks related to the acquisition and 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 we acquire;

·

drilling, operating and other cost overruns;

·

an inability to integrate successfully the properties we acquire;

·

the assumption of liabilities;

·

limitations on rights to indemnity from the seller;

·

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

·

losses of key employees.

 

 

 Moreover, the EPA proposed effluent limitations for the pretreatment and discharge of wastewater resulting from hydraulic fracturing activities to publicly owned treatment works. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. Further, the Bureau of Land Management has adopted final rules regulating hydraulic fracturing on public lands.  These rules include requirements on drillers to disclose the chemicals used in hydraulic fracturing operations and new requirements for well casing, groundwater protections, and wastewater storage.  We are currently evaluating the impact of these rules on our operations.  The EPA has also announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals  If hydraulic fracturing is further regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operations restrictions and also to associated permitting delays and potential increases in costs.  Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we ultimately are able to produce.

Our hedging transactions will expose us to counterparty credit risk.

 

We may engage in hedging transactions to reduce, but not eliminate, the effect of volatility in oil, gas and other hydrocarbon prices. Our hedging transactions will expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the derivative contract.  We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform.  Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

production.  Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases.  It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil, natural gas and natural gas liquids revenues becoming more sensitive to commodity price changes. Our General Partner will not be liable for any losses we incur as a result of our hedging policy or the implementation of that policy.

 

 

During 2010, President Obama signed into law the Dodd–Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act.  Among other things, the Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to enact regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over–the–counter market.

 

In its rulemaking under the new legislation, the CFTC has issued numerous new regulations, including on November 5, 2013, a proposed rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions).  The CFTC has not yet issued a final rule on position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions.

 

The Dodd-Frank Act and the regulations enacted thereunder by the CFTC generally mandate that all swaps are required to be: (i) cleared through derivatives clearing organizations, (ii) traded on registered exchanges, and (iii) subject to mandatory posting of initial and variation margin as credit support. In addition, the Dodd-Frank Act and the CFTC’s regulations thereunder provide exemptions for commercial end users (such as us) using swaps to hedge their commercial risk from these clearing, exchange-trading and margin-posting requirements, thereby allowing commercial end-users to enter into over–the–counter, bilaterally negotiated swaps for their hedging transactions.  The CFTC has not yet issued a final rule on capital requirements for swap dealers. However, it is possible that our counterparties in respect of their over-the-counter (i.e., uncleared) hedging transactions with us will be subject to capital requirements. Similarly, with respect to our counterparties’ uncleared swaps with third parties entered into in order to perform under their uncleared hedging transactions with us, our counterparties may be subject to margin-posting requirements.  If the regulations ultimately adopted require our counterparties to maintain higher capital levels or to post margin in connection with entering into hedging transactions with us, the costs of which could be passed through to us, then our hedging would become more expensive and we may decide to alter our hedging strategy.

would be able to collect all or a significant portion of amounts owed.  In addition, such events might force such purchasers to reduce or curtail their future purchase of our production and services, which could have a material adverse effect on our results of operations and financial condition.

 

We plan to rely on drilling to fully develop the properties we acquire. If our drilling is unsuccessful, our cash available for distributions and financial condition will be adversely affected.

 

We have and plan to acquire oil and gas properties that are not fully developed, and require that we engage in drilling to fully exploit the reserves attributable to the properties.  Our drilling will involve numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs.  We may incur significant expenditures to drill and complete wells, including cost overruns.  Additionally, current geoscience technology may not allow us 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 we 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 our common units and for servicing any debt obligations.

 

Our 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;

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

 

Our business activities are subject to operational risks, including:

·

damages to equipment caused by adverse weather conditions, including tornadoes, 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 spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives.

 

Any of these events could adversely affect our operator’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 our business and/or the business of third parties.

 

As is customary in the industry, we will maintain insurance against some but not all of these risks.  Additionally, we may elect not to obtain insurance if we believe 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 our business activities, financial condition, results of operations and ability to pay distributions to holders of our common units and service our debt obligations.

 

 

·

emergency planning and community right to know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, 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.

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

 

Our 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 our operations in compliance with these laws and regulations, we 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 our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs.  In addition, regulations regarding resource conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil, natural gas and natural gas liquids we may produce and sell.

 

We are 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 our operations, the possibility exist that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs.  If we are not able to recover the resulting costs through insurance or increased revenues, our ability to pay distributions to holders of our common units and service our debt obligations could be adversely affected.

 

an intention to introduce legislation to curb the EPA’s regulatory authority over GHGs.  The adoption and implementation of any legislation or regulatory programs imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil, natural gas and natural gas liquids that we produce.

 

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us 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 we plan to engage in may be adversely affected.  Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate-related damages to our facilities in our 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 our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom we have a business relationship.  We 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, our ability to obtain water in sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.

 

We expect 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. These rules and any revised rules may require the installation of equipment to control emissions on producing properties we acquire.

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

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. Our operators depend 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 our General Partner and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our 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 our 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 we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

Risks Related to the JOBS Act

 

We are an emerging growth company under the JOBS Act and we intend to take advantage of reduced disclosure and governance requirements applicable to emerging growth companies, which could result in our common units being less attractive to investors.

 

We are an emerging growth company, as defined in the JOBS Act, and we intend 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 our 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.  We cannot predict if investors will find our common units less attractive because we will rely on these exemptions.  We expect to take advantage of these reporting exemptions until we are no longer an emerging growth company, which in certain circumstances could be for up to five years.

 

·

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 our 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.

We currently intend to take advantage of all of the reduced regulatory and reporting requirements that will be available to us so long as we qualify as an emerging growth company.  

 

Tax Risks to Common Unitholders

 

Our tax treatment depends on our 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 us as a corporation or we become subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution to our unitholders.

 

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

 

If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% 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 us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us 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 our common units.

 

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. We 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.

  

We cannot assure you that we 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 we determine that we are an “operator” with respect to our oil and gas wells, our determination is not binding on the IRS. The IRS may assert that we are not an “operator” with respect to one or more of our oil or gas wells at the time that IDCs are incurred. If the IRS were successful in such a challenge, we and, therefore, you, would not be entitled to deduct the IDCs incurred in connection with such wells.

 

If we are eligible to deduct IDCs, we cannot assure you that IDCs will be deductible in any given year.

 

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

 

The IRS could challenge the timing of our 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 our wells may not be drilled during the year when we pay IDCs pursuant to a drilling contract. As a result, we could fail to satisfy the requirements to deduct the IDCs in the year when paid and/or the IRS may challenge the timing of our deduction of prepaid IDCs.

Section 199 deduction to any particular common unitholder.  We encourage you to consult your tax advisor to determine whether the Code Section 199 deduction would be available to you.

 

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 common 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 our 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 our 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 our taxable income.

 

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of the partnership for U.S. federal income tax purposes.

 

We will be considered to have terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For example, an exchange of 50% of our capital and profits could occur if, in any twelve-month period, holders of our common units sell at least 50% of the interests in our capital and profits. Our termination would, among other things, result in the closing of our taxable year for all holders of common units and could result in a deferral of certain deductions allowable in computing our taxable income.

 

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 – Liquidity and Capital Resources: Oil and Gas Properties”, and “Item 8. Financial Statements and Supplementary Data – Note 3. Oil and Gas Investments” contained herein.

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.

 

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. 333-197476) was declared effective by the Securities and Exchange Commission on January 22, 2015.  Under the public offering we are making under the Registration Statement (as amended and supplemented), we are offering common units of limited partner interest (the “common units”) on a best-efforts basis with the maximum offering up to $2,000,000,000 of capital, consisting of 100,263,158 common units. As of December 31, 2016, the Partnership had completed the sale of 14,582,963 common units for total gross proceeds of $286.4 million and proceeds net of offering costs, including selling commissions and marketing expenses, of $267.1 million. As of December 31, 2016, 85,680,195 common units remained unsold. As of March 3, 2017 the common units were held by approximately 4,300 unitholders. The offering will expire on April 24, 2017, 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 “Dealer Manager”) and is continuing at $20.00 per unit.

Upon formation of the Partnership, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering in August 2015, 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 continue to be reimbursed for its documented third-party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.  Under our agreement with the Dealer Manager, the Dealer Manager receives a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold.  The Dealer Manager will also be paid a contingent incentive fee, 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, 2016, the total contingent fee is approximately $11.5 million.

There is currently no established public trading market in which the Partnership’s common units are traded. The net proceeds of the public offering were used as follows:

Use of Proceeds

The following tables set forth information concerning the ongoing best-efforts offering and the use of proceeds from the offering as of December 31, 2016.

 

Units Registered
						5,263,158		Units		$	19.00		per unit		$	100,000,002
						95,000,000		Units		$	20.00		per unit			1,900,000,000
Totals:						100,263,158		Units							$	2,000,000,002
Units Sold
						5,263,158		Units		$	19.00		per unit		$	100,000,002
						9,319,805		Units		$	20.00		per unit			186,396,100
Totals:						14,582,963		Units							$	286,396,102
Expenses of Issuance and Distribution of Units
	1.		Underwriting commissions												$	17,183,766
	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													2,105,542
	Total Expenses of Issuance and Distribution of Common Shares															19,289,308
Net Proceeds to the Partnership															$	267,106,794
	1.		Purchase of oil, gas and natural gas liquids properties (net of debt, proceeds and repayment including interest and acquisition costs)												$	165,199,443
	2.		Deposits and other costs associated with potential oil, natural gas and natural gas liquids acquisitions													10,000,000
	3.		Repayment of other indebtedness, including interest expense paid													-
	4.		Investment and working capital													81,458,370
	5.		Fees and expenses of third parties													-
	6.		Other													-
	7.		Distributions													10,448,981
Total Application of Net Proceeds to the Partnership															$	267,106,794

 

Class B Units

Upon entering into the management agreement with the Former Manager on August 19, 2015, the Partnership issued 100,000 Class B units to Incentive Holdings, an affiliate of the Former Manager. Upon the termination of the Management Agreement and in accordance with the terms therewith, 37.5% of the Class B units owned by Incentive Holdings were canceled. As of December 31, 2016, the outstanding Class B units totaled 62,500. The Partnership may issue up to 37,500 Class B units, the amount cancelled in conjunction with the termination of the Management Agreement. The Class B units provide for certain distribution rights described below.

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 or with respect to Class B units and will not make the contingent, incentive payments to the Dealer Manager, until Payout occurs.

  

The Partnership Agreement provides that Payout 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 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, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000; (iii) to the Dealer Manager, as the contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any, to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the contingent incentive fee under the Dealer Manager Agreement;

·

Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000; (iii) the remaining amount to the Record Holders of outstanding common units, 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, 2016, the Partnership paid distributions of $1.40 per common unit or $10.4 million, and for the year ended December 31, 2015, the Partnership paid distributions of $0.51 per common unit or $1.3 million. The Partnership began paying distributions upon reaching the minimum offering in August 2015.

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

Item 6.  Selected Financial Data

Not applicable.

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

Overview

The Partnership was formed as a Delaware limited partnership.  The General Partner is Energy 11 GP, LLC (the “General Partner”).  The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership is offering common units of limited partner interest (the “common units”) on a best-efforts basis, with the maximum offering up to $2,000,000,000 of capital, consisting of 100,263,158 common units.  The Partnership’s Registration Statement on Form S-1 (File No. 333-197476) was declared effective by the SEC on January 22, 2015.  As of August 19, 2015, the Partnership completed the sale of the minimum offering of 1,315,790 common units for gross proceeds of $25 million.  Upon raising the minimum offering amount, the holders of the common units were admitted and the Partnership commenced operations. Through December 31, 2016, the Partnership had sold a total of 14,582,963 common units for gross proceeds of $286.4 million.

 

The Partnership has no officers, directors or employees. Instead, the General Partner manages the day to day affairs of the Partnership. All decisions regarding the management of the Partnership made by the General Partner are made by the Board of Directors of the General Partner and its officers.

The Partnership was formed to acquire and develop oil and gas properties located onshore in the United States. The Partnership will seek to acquire working interests, leasehold interests, royalty interests, overriding royalty interests, production payments and other interests in producing and nonproducing oil and gas properties. On December 18, 2015, the Partnership completed its purchase of an approximate 11% working interest in approximately 215 existing producing wells and approximately 262 future development locations in the Sanish field located in Mountrail County, North Dakota (the “Sanish Field Assets”). The Sanish Field Assets are a part of the Bakken shale formation in the Greater Williston Basin.

As of December 31, 2016, the Partnership had 216 producing wells, with approximately 257 future development locations. The Partnership’s assets owned at December 31, 2016 are non-operated oil and gas wells, substantially all of which are managed and operated by Whiting Petroleum Company (“Whiting”). Whiting, a publicly traded oil and gas company, operates the assets on behalf of the Partnership and other working interest owners.

On January 11, 2017, the Partnership completed the purchase of an additional 11% working interest in the Sanish Field Assets. The purchase price was $130.0 million and was funded by the Partnership with $90.0 million in cash (from the sale of the Partnership’s common units in its ongoing, best-efforts offering) and a $40.0 million promissory note (“Seller Note”). The Partnership paid the $40.0 million Seller Note in full on February 23, 2017. The Seller Note bore interest at 5% per annum up to the payoff date.

Current Price Environment

Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control. Historically, energy commodity prices have been volatile; oil prices declined throughout 2015 and in the first quarter of 2016, prices had fallen to the lowest levels since October 2003. Commodity prices increased to 52-week highs by December 2016, but 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. In addition to commodity price fluctuations, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.

		Year (Period) Ended December 31,
		2016				2015
Average market closing prices (1)
Oil (per Bbl)		$	43.40			$	48.79
Natural gas (per Mcf)		$	2.52			$	2.62

Partnership 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, drill new wells on existing leasehold sites and/or acquire additional reserves.

As specified by the SEC, the prices for oil, natural gas and NGL used to calculate Partnership reserves were the average prices during the 2016 calendar year, with the average determined using the price on the first day of each month. The prices, before price differentials, utilized in calculating total estimated proved reserves at December 31, 2016 were $42.75 per barrel of oil and $2.48 per thousand cubic feet (Mcf) of natural gas. The prices, after price differentials, were $36.25 per barrel of oil, ($0.38) per Mcf of natural gas and $4.70 per barrel of NGL.

Results of Operations for Years 2016 and 2015

The Partnership closed on the purchase of the Sanish Field Assets on December 18, 2015. Because the Partnership only had 14 days of revenues and operating expenses in 2015, the operating results between the years ended December 31, 2016 and 2015 is not comparable, except as otherwise indicated below.

---

(1)	All production and cost figures are derived from the Partnership’s ownership of the properties from December 18, 2015 through December 31, 2015.

 

leasehold. Production in 2017 will be dependent on the investment in existing wells and the development of new wells. If the Partnership or our operator is unable or it is not cost beneficial to invest in existing wells or develop new wells, production will decline.

Operating Costs and Expenses

Lease Operating Expenses (“LOE”)

For the years ended December 31, 2016 and 2015, LOE was $3.8 million and $149,072, respectively, and LOE per BOE of production were $5.81 and $5.35, respectively. While monthly LOE has stabilized during 2016, production has decreased over the same period, which directly led to an increase in LOE per BOE of production throughout the year. LOE for the fourth quarter of 2016 was $6.73 per BOE of production.

Gathering and Processing Expenses

For the years ended December 31, 2016 and 2015, gathering and processing fees were $1.7 million and $16,689, respectively. Gathering and processing costs per BOE of production were $2.66 and $0.60, respectively. During the third quarter of 2016, the Partnership’s operator amended its gathering and processing contract, which led to increases in gathering and processing costs. Higher third-party fractionation expenses also contributed to the significant increase in gathering and processing costs, in total and per BOE of production, during the second half of 2016. Costs in the fourth quarter of 2016 were $3.36 per BOE of production.

From time to time, expenses will be incurred on a producing well to restore or increase production. For the years ended December 31, 2016 and 2015, workover expenses were $0.3 million and $1,450, respectively. Workover expenses per BOE of production were $0.41 and $0.05, respectively. The Partnership authorized substantial rework on two wells during 2016, leading to the increase in workover expenses per BOE of production. These costs will vary depending on the need for specific well rework. Costs in the fourth quarter of 2016 were $0.57 per BOE of production.

Production Taxes

North Dakota’s oil tax structure is comprised of two main taxes: the production tax and the extraction tax. The production tax is 5% of gross revenue. Beginning January 1, 2016, the extraction tax rate is also 5% of the gross value at the well. This rate can increase to 6% if the high-price trigger, defined as the average price of a barrel of oil exceeding a trigger price of $90 for each month in any consecutive three-month period, is in effect. The 6% rate would remain in effect until the average price is less than $90 per barrel for each month in any consecutive three-month period.

The production tax on gas is subject to a price index change on July 1 of each calendar year. The rate for July 1, 2016 through June 30, 2017 is $0.0601 per Mcf. The previous rate from July 1, 2015 through June 30, 2016 was $0.1106 per Mcf.

 

terminated in April 2016. The reduction in management fees is partially offset by the Partnership utilizing additional external resources to replace certain services previously provided by the Former Manager. Therefore, the Partnership has increased accounting and consulting fees, which are classified as general and administrative costs.

Costs related to the acquisition of the Sanish Field Assets for the years ended December 31, 2016 and 2015 were $0.1 million and $0.3 million. These costs include legal, accounting and due diligence associated with the 2017 and 2015 purchases of the Partnership’s working interests in the Sanish Field Assets.

General and Administrative Costs

General and administrative costs for the years ended December 31, 2016 and 2015 were $1.3 million and $0.7 million, respectively. The principal components of general and administrative expense are accounting, legal and consulting fees. General and administrative expenses for the twelve months ended December 31, 2016 exceeded those of the prior year due to a full year of operations following the closing of the Partnership’s interest in the Sanish Field Assets in December 2015 as well as the Management Agreement that was terminated in April 2016.

Interest Expense

Interest expense, net, for the years ended December 31, 2016 and 2015 was $6.1 million and $0.3 million, respectively. The increase in interest expense, net, during 2016 as compared to 2015 was primarily due to (a) nine months of interest expense on the $97.5 million Seller Note related to the Partnership’s initial 2015 acquisition of its interest in the Sanish Field Assets (Seller Note paid in full in September 2016), (b) nine months of amortization of the mark-to-market adjustment on the $97.5 million Seller Note; (c) amortization of deferred origination costs on the $97.5 million Seller Note; and (d) accretion of the Partnership’s deferred purchase price and contingent consideration liabilities incurred with the 2015 acquisition.

Management Agreement

At the initial closing of the sale of common units on August 19, 2015, the Partnership entered into a management services agreement (the “Management Agreement”) with E11 Management LLC (the “Former Manager”) to provide management and operating services regarding substantially all aspects of the Partnership. Under the Management Agreement, the Former Manager agreed to provide management and operating services to the Partnership in exchange for a monthly fee. In addition, the Partnership issued 100,000 Class B units to an affiliate of the Former Manager upon entering into the Management Agreement. The Class B units entitle the holder to receive a portion of distributions made after Payout, as defined in Distributions below.

The Former Manager was formed by Aubrey K. McClendon. The Management Agreement was terminable by the Partnership if, among other reasons, Mr. McClendon, the Former Manager’s key employee, ceased to be employed by the Former Manager and the Partnership did not approve of a proposed replacement of such key employee. On March 2, 2016, Mr. McClendon died in a car accident. Following Mr. McClendon’s death and subsequent correspondence between the Former Manager and the Partnership, on April 5, 2016, the Partnership elected not to approve a replacement key employee for Mr. McClendon and exercised its right to terminate the Management Agreement. Accordingly, the fees under the Management Agreement were no longer accrued as of the effective date of termination. Also, upon termination of the Management Agreement and in accordance with the terms therewith, 37.5% of the Class B units owned by Incentive Holdings were canceled. As of December 31, 2016, the Class B units owned by Incentive Holdings totaled 62,500.

Supplemental Non-GAAP Measure

The Partnership uses “EBITDAX”, defined as Earnings before Interest, Income Taxes, Depreciation, Depletion, Amortization and Exploration Expenses, as a key supplemental measure of its operating performance. This non-GAAP financial measure should be considered along with, but not as alternatives to, net income (loss), operating income (loss), cash flow from operating activities or other measures of financial performance presented in accordance with GAAP. EBITDAX is not necessarily indicative of funds available to fund the Company’s cash needs, including its ability to make cash distributions. Although EBITDAX, as calculated by the Partnership, may not be comparable to EBITDAX as reported by other companies that do not define such 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 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 operator.

The following table reconciles the Partnership’s GAAP net loss to EBITDAX for the years ended December 31, 2016 and 2015.

Liquidity and Capital Resources

The Partnership’s principal source of liquidity will be the proceeds of the best-efforts offering until it expires in April 2017, cash on hand, and the cash flow generated from properties the Partnership has acquired. In addition, the Partnership may borrow funds to pay operating expenses, distributions, make acquisitions or for other capital needs of the Partnership. In September 2016, the Partnership repaid the Seller Note that was entered into in conjunction with the initial purchase of the Sanish Field Assets.

The Partnership anticipates that cash on hand, cash flow from operations and proceeds of the best-efforts offering will be adequate to meet its anticipated liquidity requirements for at least the next 12 months, including the acquisition of the additional approximate 11% working interest in the Sanish Field Assets for a purchase price of $130.0 million, as discussed above.

 

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 (owned by the General Partner), with respect to Class B units or the contingent, incentive payments to the Dealer Manager, until Payout occurs.

The Partnership Agreement provides that Payout 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 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, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000; (iii) to the Dealer Manager, as the contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any, to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the contingent incentive fee under the Dealer Manager Agreement;

·

Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000; (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest.

The Partnership may issue up to 37,500 additional Class B units, the amount of Class B units canceled in conjunction with the termination of the Management Agreement discussed above.

For the year ended December 31, 2016, the Partnership made distributions of $1.40 per common unit, or $10.4 million, and generated approximately $6.9 million in cash from operations.

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 rate of distribution ($1.40 per unit per year) will be based on its ability to increase its cash generated from operations. As there can be no assurance that the Partnership’s current assets will or that the Partnership can acquire additional properties that provide income at this level, there can be no assurance as to the classification or duration of distributions at the current rate. Proceeds of the offering which are distributed are not available for investment in properties.

Oil and Gas Properties

The Partnership incurred approximately $1.7 million in capital expenditures for the year ended December 31, 2016 and expects to invest approximately $10.0 to $15.0 million in capital expenditures during 2017, which includes drilling and completion of approximately five to ten new wells. If oil, natural gas and NGL prices during 2017 are not at levels that make it cost beneficial to drill and complete new wells, the Partnership expects to invest approximately $1.5 to $3.0 million in capital expenditures in 2017. However, the capital expenditure plan has the flexibility to adjust should the commodity price environment change. A decrease in oil, natural gas and NGL prices will lead to a reduction in capital expenditures and lower oil, NGL and natural gas production volumes.

Since the Partnership is not the operator of any of its oil and natural gas properties, it is difficult to predict levels of future participation in the drilling and completion of new wells and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast for 2017 and current estimated capital expenditures could be significantly different from amounts actually invested.

The Partnership expects to fund overhead costs and capital additions related to the drilling and completion of wells primarily from cash provided by operating activities and cash on hand.

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 titled “Related Parties” in Part II, Item 8 of this Form 10-K and in Part III, Item 13 — “Certain Relationships and Related Transactions, and Director Independence” below.

Critical Accounting Policies

 

The discussion and analysis of our 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 us 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 our 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. We base 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 our operating environment changes and as new events occur.

 

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 we are 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

We assess our 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, we recognize 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 our 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.

 

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 our reserves. Independent reserve engineers prepare our reserve estimates at the end of each year.

 

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

 

Accounting for Asset Retirement Obligations

 

We have significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. Our 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.

 

We record an asset retirement obligation (“ARO”) and capitalize 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

 

Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. Virtually all of our 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.

 

Subsequent Events

On January 11, 2017, the Partnership closed on the purchase of all of the issued and outstanding limited liability company interests of Kaiser-Whiting, LLC, which represents an additional approximate 11% non-operated working interest in the Sanish Field Assets. The purchase price of $130.0 million, subject to customary adjustments, consisted of cash payments totaling $90.0 million and the delivery of a promissory note in favor of the seller of $40.0 million. The Partnership paid the $40.0 million promissory note in full on February 23, 2017. With the closing of the purchase, the Partnership now owns an approximate 22-23% non-operated working interest in the Sanish Field Assets. See further discussion in Note 3. Oil and Gas Investments in the footnotes to our financial statements.

In January 2017, the Partnership declared and paid $1.6 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

In January 2017, the Partnership closed on the issuance of approximately 1.1 million common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $21.7 million and proceeds net of selling and marketing costs of approximately $20.4 million.

In February 2017, the Partnership declared and paid $1.7 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

Item 7A.  Quantitative and Qualitative Disclosure About Market Risk

Not Applicable.

 

 

Item 8.  Financial Statements and Supplementary Data

Financial Statements

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

General Partner

Energy 11, L.P.

 

We have audited the accompanying consolidated balance sheets of Energy 11, L.P. (a Delaware limited partnership) and its subsidiaries (the “Partnership”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, partners’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy 11, L.P. and its subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

 

/S/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

March 3, 2017

 

Energy 11, L.P.

Consolidated Balance Sheets

 

See notes to consolidated financial statements.

 

Energy 11, L.P.

Consolidated Statements of Operations

 

 

Energy 11, L.P.

Consolidated Statements of Partners' Equity (Deficit)

 

 

Energy 11, L.P.

Consolidated Statements of Cash Flows

 

 

See notes to consolidated financial statements.

Energy 11, L.P.

Notes to Consolidated Financial Statements

 

Note 1.  Partnership Organization

 

Energy 11, L.P. (together with its wholly-owned subsidiaries, the “Partnership”) was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership is offering common units of limited partner interest (the “common units”) on a best-efforts basis with the maximum offering up to $2,000,000,000 of capital, consisting of 100,263,158 common units. The Partnership’s offering was declared effective by the Securities and Exchange Commission (“SEC”) on January 22, 2015. As of August 19, 2015, the Partnership completed the sale of the minimum offering of 1,315,790 common units. The subscribers were admitted as Limited Partners of the Partnership at the initial closing of the offering and the Partnership has been admitting additional Limited Partners monthly since that time.

The Partnership’s primary investment objectives are to (i) acquire producing and non-producing oil and gas properties with development potential, 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 – 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.

 

The General Partner of the Partnership is Energy 11 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. David Lerner Associates, Inc. (the “Dealer Manager”) is 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 consolidated 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 ongoing best-efforts offering of common units by David Lerner Associates, Inc., who receives a selling commission and a marketing expense allowance based on proceeds of the common 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, 2016 and 2015, the Partnership had sold 14.6 million and 4.5 million common units for gross proceeds of $286.4 million and $85.2 million, respectively, and proceeds net of offering costs of $267.1 million and $78.3 million, respectively.

 

Property and Depreciation, Depletion and Amortization

 

We account for our 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.

Impairment

We assess our 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, we recognize 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 our 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.

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 we have an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2016, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. For the year ended December 31, 2016, the Partnership’s oil, natural gas and NGL sales were through two operators. Whiting Petroleum Corporation (“Whiting”) is the operator of 99% the Partnership’s properties. 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.

Asset Retirement Obligation

We have significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. Our 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.

 

We record an asset retirement obligation (“ARO”) and capitalize 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.

The following table shows the activity for the years ended December 31, 2016 and 2015, relating to the Partnership’s asset retirement obligations:

 

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.

Oil, NGL and Natural Gas Sales and Natural Gas Imbalances

We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production.

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, 2016 and 2015, there were no such costs accrued.

Use of Estimates

 

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of crude 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 crude 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 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 crude oil, natural gas and NGL as estimated by management are used. Crude 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 crude oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of crude 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.

Revenue Recognition

 

Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. Virtually all of our 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.

Loss Per Common Unit

 

Basic net loss per common unit is computed as net loss divided by the weighted average number of common units outstanding during the period. Diluted net loss per 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, 2016 and 2015. As a result, basic and diluted outstanding common units were the same. The Class B Units and Incentive Distribution Rights are not included in loss per common unit until such time that it is probable Payout (as discussed in Note 7) would occur.

 

Recent Accounting Standards

 

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2017-01, Business Combinations (Topic 805), which amends the existing accounting standards to clarify the definition of

a business and assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public entities, the guidance is effective for reporting periods beginning after December 15, 2017, including interim periods within those periods, and should be applied prospectively on or after the effective date. Early application is permitted for transactions that occur before the issuance or effective date of this amendment, provided the transaction has not been reported in financial statements that have been issued or made available for issuance. The Partnership plans to adopt the standard effective January 1, 2017. Prior to the adoption of this standard, the Partnership’s acquisitions of oil and gas properties were accounted for as existing businesses, and therefore all transaction costs associated with the acquisitions, including title, legal, accounting, brokerage commissions and other related costs were expensed as incurred. The adoption of this standard will not affect transactions that occurred prior to the effective date; however, the Partnership will evaluate any future acquisition(s) of oil and gas properties under the revised standard and account for the acquisition as either an asset purchase or business combination depending on the particular facts and circumstances of the acquisition.

In November and August 2016, the FASB issued ASU 2016-18 and ASU 2016-15. Each update addresses and clarifies specific statement of cash flow (Topic 230) issues with the objective to reduce existing diversity in practice. For public entities, the guidance is effective for reporting periods beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted. This standard is not expected to have a material impact on the Partnership’s consolidated statements of cash flows.

Throughout 2016, the FASB has issued several updates to clarify specific topics originally described in ASU 2014-09, Revenue from Contracts with Customers (Topic 606). These updates include ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20. ASU 2014-09, released in May 2014, 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 was to be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. However, the FASB deferred the effective date by one year in August 2015 in ASU 2015-14. The Partnership currently does not believe this standard will have a material effect on the timing of its revenue recognition, its financial position or its results from operations. However, the Partnership will continue to evaluate the impact, if any, of ASU 2014-09 as well as the related subsequent pronouncements released.

In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718), which simplifies several aspects of accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. For public entities, the guidance is effective for reporting periods beginning after December 15, 2016, and it is not expected to have a material impact on the Partnership’s consolidated financial statements.

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 and making targeted changes to lessor accounting. The standard is effective for annual periods beginning after December 15, 2018, and interim periods within those years, with early adoption permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. The Partnership is currently evaluating the impact of adopting the new standard on its consolidated financial statements.

Note 3.  Oil and Gas Investments

As of December 31, 2016, the Partnership owns an approximate 11% non-operated working interest in approximately 216 existing producing wells and approximately 257 future development locations in the Sanish field located in Mountrail County, North Dakota (the “Sanish Field Assets”). The Partnership acquired its interest in the Sanish Field Assets on December 18, 2015 for approximately $159.1 million, subject to post-closing adjustments. During the first half of 2016, the Partnership and the sellers (“Sellers”) adjusted the purchase price for the settlement of operating activity that occurred prior to the closing date. The net impact of the purchase price adjustment was an increase to the purchase price of the asset of approximately $0.5 million. The Partnership has expensed, as incurred, transaction costs associated with the acquisition of the Sanish Field Assets. These costs included but were not limited to due diligence, reserve reports, legal and engineering services and site visits. The Partnership incurred transaction costs of $78,000 and $0.3 million in the years

ended December 31, 2016 and 2015. The transaction costs incurred in 2016 primarily relate to the due diligence for the 2017 acquisition of additional interests in the same Sanish Field Assets discussed below.

The Partnership is a non-operator of the Sanish Field Assets. Whiting, one of the largest producers in this basin, is the operator.

The following unaudited pro forma financial information for the period ended December 31, 2015, has been prepared as if the acquisition of the Sanish Field Assets had occurred on January 1, 2015.  The unaudited pro forma financial information was derived from the historical Statement of Operations of the Partnership and the historical information provided by the Sellers.  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 Sanish Field Assets and related financing occurred on the basis assumed above, nor is such information indicative of the Partnership’s expected future results of operations.

On January 11, 2017, the Partnership completed the purchase of an additional 11% working interest in the Sanish Field Assets. The purchase price was $130.0 million and was funded by the Partnership with $90.0 million in cash (from the sale of the Partnership’s common units in its ongoing, best-efforts offering) and a $40.0 million promissory note (“Seller Note”). The Partnership paid the $40.0 million Seller Note in full on February 23, 2017.  The Seller Note bore interest at 5% per annum up to the payoff date.

Note 4.  Note Payable

As part of the financing for the purchase of the Sanish Field Assets, on December 18, 2015, the Partnership executed a note in favor of the Sellers (“Seller Note”) of the assets in the original principal amount of $97.5 million. On September 29, 2016, the Partnership paid the Seller Note in full.

On June 23, 2016, the Seller Note was increased by $5.0 million to satisfy the contingent payment due to the Sellers as defined in the First Amendment of the Interest Purchase Agreement. The Partnership was given the one-time right (exercisable between June 15, 2016 through June 30, 2016) to elect to satisfy the contingent payment in full by paying to Sellers $5.0 million at the time of election or by increasing the amount of the Seller Note by $5.0 million. On June 23, 2016, the Partnership exercised that right by increasing the amount of the Partnership’s note with the Sellers by $5.0 million. If the Partnership had not exercised the one-time right, the contingent payment would have ranged from $0 to $95 million depending on the average of the monthly NYMEX:CL strip prices as of December 31, 2017 for future contracts during the delivery period beginning December 31, 2017 and ending December 31, 2022.

 

In accordance with the Seller Note, because the Partnership had not fully repaid all amounts outstanding under the note on or before June 30, 2016, the Partnership paid a deferred origination fee equal to $250,000 during the three months ended June 30, 2016. The deferred origination fee was amortized and expensed in full during the third quarter of 2016 and is included in “Interest expense, net” in the consolidated statements of operations.

As of December 31 2015, the outstanding balance on the note was $85.0 million and the carrying value of the note, which approximates its fair market value, was $81.7 million. 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.

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, 2016 and 2015, there were no transfers in or out of Level 1, Level 2, or Level 3 Assets and liabilities measured on a recurring basis.

The Partnership’s financial instruments exposed to concentrations of credit risk primarily consist of cash and cash equivalents and accounts receivable. The carrying values for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows and current market conditions. See “Note 4. Note Payable” for the fair value discussion on the debt.

Items required to be measured at fair value on a recurring basis by the Partnership include the contingent consideration included in the Partnership’s consideration for the 2015 Sanish Field Asset purchase. Within the valuation hierarchy, the Partnership measured the fair value of the contingent consideration using Level 3 inputs. As of December 31, 2015, the fair value of the contingent consideration was $4,743,752. The inputs for this instrument were significant and unobservable and therefore classified as Level 3 inputs. Management calculated the fair value of the contingent consideration (absent the $5.0 million option) as of December 18, 2015, the Sanish Field Assets acquisition close date, to be $12.5 million. As this was substantially greater than the $5.0 million option, the Partnership believed a market participant would likely view the $5.0 million option as highly probable of being exercised and, therefore, valued the contingent consideration at $5.0 million, discounted to the expected exercise date. The calculation of this liability was based upon a $5.0 million payment to be made to Kaiser-Whiting between June 15, 2016 and June 30, 2016 and a discount rate that was reflective of the Partnership’s market adjusted borrowing rate, as of December 18, 2015, of 11.15%. As discussed in “Note 4. Note Payable”, the Partnership satisfied the contingent payment by increasing its Seller Note on June 23, 2016 by $5.0 million; therefore, the contingent consideration has no value as of December 31, 2016.

 

Note 6. Management Agreement

At the initial closing of the sale of its common units on August 19, 2015, the Partnership entered into a Management Services Agreement (the “Management Agreement”) with E11 Management, LLC, (the “Former Manager”), and E11 Incentive Holdings, LLC, an affiliate of the Former Manager (“Incentive Holdings”), whereby the Former Manager agreed to provide management and operating services regarding substantially all aspects of the Partnership’s business. The Former Manager was formed by Aubrey K. McClendon and he served as its Chief Executive Officer.

Under the Management Agreement, the Former Manager agreed to provide management and other services to the Partnership including, but not limited to, the following:

·	Identifying and evaluating oil and natural gas properties for acquisition, development, integration, sale or monetization;

·	Conducting (or overseeing one of its affiliated companies or third-parties to conduct) drilling, completion, production, marketing and hedging operations as the operator of the Partnership’s oil and natural gas properties;

·	Overseeing the drilling, completion, production, marketing and hedging operations of our oil and natural gas properties operated by other persons or entities;

·	Identifying and evaluating financing alternatives for acquisitions of producing oil and natural gas properties; and

·	Managing the financial, accounting and other back office support functions associated with the drilling, completion, production, marketing and hedging of the Partnership’s oil and natural gas properties.

Pursuant to the Management Agreement, the Partnership agreed to pay the Former Manager a monthly fee.

 

Upon entering into the Management Agreement, the Partnership issued 100,000 Class B units to Incentive Holdings. The Class B units entitle the holder to receive a portion of distributions made after Payout, as defined in Note 7 below.

The Management Agreement was terminable by the Partnership if, among other reasons, Mr. McClendon, the Former Manager’s key employee, ceased to be employed by the Former Manager and the Partnership did not approve of a proposed replacement of such key employee. On March 2, 2016, Mr. McClendon died in a car accident. Following Mr. McClendon’s death and subsequent correspondence between the Former Manager and the Partnership, on April 5, 2016, the Partnership elected not to approve a replacement key employee for Mr. McClendon and exercised its right to terminate the Management Agreement. Accordingly, the fees under the Management Agreement were no longer accrued as of the effective date of termination. Also, upon termination of the Management Agreement and in accordance with the terms therewith, 37.5% of the Class B units owned by Incentive Holdings were canceled. As of December 31, 2016, the Class B units owned by Incentive Holdings totaled 62,500.

Substantially all of the Partnership’s properties are currently being operated by Whiting, an independent third party. Since the Partnership only owns a non-operating interest in the Sanish Field Assets, most of the services that the Former Manager had been contracted to perform are being performed by Whiting, as operator of those properties. Consequently, the termination of the Management Agreement has not had and the Partnership does not anticipate that the termination will have an adverse effect on its operations.

For the years ended December 31, 2016 and 2015, the Partnership incurred fees and reimbursable costs of approximately $0.9 million and $0.5 million, respectively, under the Management Agreement.

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.

 

As of August 19, 2015, the Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit.  In March 2016, the Partnership completed the sale of 5,263,158 common units at $19.00 per common unit. All subsequent shares of common units are being sold at $20.00 per common unit. As of December 31, 2016 and 2015, the Partnership had completed the sale of 14.6 million and 4.5 million common units for total gross proceeds of $286.4 million and $85.2 million, respectively, and proceeds net of offering costs including selling commissions and marketing expenses of $267.1 million and $78.3 million, respectively.

The Partnership intends to continue to raise capital through its best-efforts offering by the Dealer Manager at $20.00 per common unit. The Partnership has extended its offering through April 24, 2017; however, the offering will be terminated if all of the common units are sold before then. Under the agreement with the Dealer Manager, the Dealer Manager receives a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, 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, 2016, the total contingent fee is approximately $11.5 million.

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 (owned by the General Partner), the Class B units or the contingent, incentive payments to the Dealer Manager, until Payout occurs.

The Partnership Agreement provides that Payout 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, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000; (iii) to the Dealer Manager, as the contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any, to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the contingent incentive fee under the Dealer Manager Agreement;

·

Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000; (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest.

The Partnership may issue up to 37,500 additional Class B units, the amount of Class B units canceled in conjunction with the termination of the Management Agreement discussed above in Note 6.

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, 2016, the Partnership paid distributions of $1.400000 per common unit, or $10.4 million. For the year ended December 31, 2015, the Partnership paid distributions of $0.510138 per common unit, or $1.3 million.

Note 8.  Related Parties

 

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

Aggregate Capitalized Costs

 

The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2016 and 2015 is as follows:

 

  

Costs Incurred

For the years ended December 31, 2016 and 2015, the Partnership incurred the following costs in oil and natural gas producing activities:

 

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, 2016 and 2015.

 

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, 2016 and 2015, 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 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.

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

 

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, 2016 were $42.75 per barrel of oil and $2.48 per Mcf 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, 2016 were $36.25 per barrel of oil, ($0.38) per Mcf of natural gas and $4.70 per barrel of NGL.

The oil, natural gas and NGL prices used in computing the Partnership’s reserves as of December 31, 2015 were $50.28 per barrel of oil, $2.59 per Mcf of natural gas, and $15.74 per barrel of NGL, 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, 2015 were $41.74 per barrel of oil, $1.46 per Mcf of natural gas and $9.77 per barrel of NGL.

The following details the changes in proved undeveloped reserves for 2015 and 2016:

 

Although the Partnership has performed limited drilling since acquisition, we anticipate that all the Partnership’s current PUD locations will be drilled and converted to PDP within five years of the date they were added. However, 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 will be removed as revisions at the time that determination is made, and in the event that it subsequently appears that any such undrilled PUD locations would not be drilled by the end of such five-year period, then the Partnership would remove the reserves associated with those locations from the its proved reserves as revisions.

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.