mcep-10k_20171231.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10–K

 

 

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

For the fiscal year ended December 31, 2017

OR

 

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

Commission File No.: 1-35374

 

Mid-Con Energy Partners, LP

(Exact name of registrant as specified in its charter)

 

 

Delaware

45–2842469

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

2431 East 61st Street, Suite 850

Tulsa, Oklahoma 74136

(Address of principal executive offices and zip code)

(918) 743-7575

(Registrant’s telephone number, including area code)

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

 

Common Units Representing Limited Partner Interests

NASDAQ Global Select Market

(Title of each class)

(Name of each exchange on which registered)

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

 

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 Web site, 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 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 or any amendment to the 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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b–2 of the Exchange Act. Check one:

Large accelerated filer

 

  

Accelerated filer

 

Non-accelerated filer

 

(Do not check if a smaller reporting company)

 

Smaller reporting company

 

Emerging Growth Company

 

 

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act).    YES      NO  

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

The aggregate market value of the common units held by non-affiliates of the registrant was $33.0 million on June 30, 2017, based on $1.36 per unit, the last reported sales price of the units on The NASDAQ Global Select Market on such date.

Documents incorporated by Reference: None.

As of February 28, 2018, the registrant had 30,116,560 common units.

 

 


 

Table of Contents

 

 

PART I

 

Item 1.

Business

6

Item 1A.

Risk Factors

16

Item 1B.

Unresolved Staff Comments

32

Item 2.

Properties

32

Item 3.

Legal Proceedings

35

Item 4.

Mine Safety Disclosures

35

 

PART II

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

36

Item 6.

Selected Financial Data

37

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

37

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

47

Item 8.

Financial Statements and Supplementary Data

48

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

72

Item 9A.

Controls and Procedures

72

Item 9B.

Other Information

72

 

PART III

 

Item 10.

Directors, Executive Officers and Corporate Governance

73

Item 11.

Executive Compensation

77

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

83

Item 13.

Certain Relationships and Related Transactions, and Director Independence

84

Item 14.

Principal Accounting Fees and Services

86

 

PART IV

 

Item 15.

Exhibits

87

 

 

 

Signatures

 

90

 

 

 

i


GLOSSARY

The following is a list of certain acronyms and terms generally used in the industry and throughout this document. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been excerpted from the applicable definitions contained in Rule 4-10(a) of Regulation S-X.

 

ARO

Asset retirement obligations.

Basin

A large depression on the earth's surface in which sediments accumulate.

Bbl

One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bbl/d

One Bbl per day

Behind pipe

Reserves associated with recompletion projects which have not been previously produced.

Boe

Barrel of oil equivalent, equals six Mcf of natural gas or one Bbl of oil based on a rough energy equivalency. This is a physical correlation of heat content and does not reflect a value or price relationship between the commodities.

Boe/d

One Boe per day.

Btu

One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Class A Preferred Units

Class A Convertible Preferred Units issued on August 11, 2016.

Class B Preferred Units

Class B Convertible Preferred Units issued on January 31, 2018.

Conventional hydraulic fracturing

Hydraulic fracturing is used to stimulate production from new and existing oil and natural gas wells. Large volumes of fracturing fluids, or “fracing fluids,” are pumped deep into the well at high pressures sufficient to cause the reservoir rock to break or fracture. Almost all frac fluid mixtures are comprised of more than 95 percent water. As the pressure builds within the well, rock beds begin to crack. More fluid is added while the pressure is increased until the rock beds finally fracture, creating channels for trapped oil and natural gas to flow into the well bore and up to the surface. The fractures are kept open with proppants made of small granular solids (generally sand) to ensure the continued flow of fluids. By creating or even restoring fractures, the surface area of a formation exposed to the borehole increases and the fracture provides a conductive path that connects the reservoir to the well. These new paths increase the rate that fluids can be produced from the reservoir formations, in some cases by many hundreds of percent.

Developed acreage

Acres spaced or assigned to productive wells or wells capable of production.

Development well

A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole

A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expense and taxes.

EOR

Enhanced oil recovery.

EPA

U.S. Environmental Protection Agency.

Exploratory well

A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

Extension well

A well drilled to extend the limits of a known reservoir.

Field

An area comprised of multiple leases in close proximity to one another that typically produce from the same reservoirs and may or may not be produced under waterflood.

GAAP

Generally Accepted Accounting Principles in the United States of America.

GHG

Greenhouse gas.

Gross wells

The number of wells in which a working interest is owned.

Injection well

A well employed for the introduction of water, gas or other fluid under pressure into an underground stratum.

LIBOR

London Interbank Offered Rate.

MBbls

One thousand Bbls.

MBoe

One thousand Boe.

MBtu

One thousand Btu.

Mboe/d

One thousand Boe per day.

Mcf

One thousand cubic feet.

Mcf/d

One thousand cubic feet per day.

MMBoe

One million Boe.

MMBtu

One million Btu.

1


MMcf

One million cubic feet of natural gas.

NASDAQ

National Association of Securities Dealers Automated Quotation System Global Select Market.

NGLs

Natural gas liquids.

Net production

Production that is owned by us, less royalties and production due others.

Net revenue interest

A working interest owner’s gross working interest in production, less any royalty, overriding royalty, production payment and net profits interests.

Net well

The total of fractional working interests owned in a gross well.

NYMEX

New York Mercantile Exchange.

Oil

Oil and condensate.

Partnership Agreement

Second Amendment to First Amended and Restated Agreement of Limited Partnership of Mid-Con Energy Partners, LP, dated as of January 31, 2018.

Preferred Units

Class A Preferred Units and Class B Preferred Units.

Preferred Unitholders

The holders of Preferred Units.

Productive well

A well that is producing or that is mechanically capable of production.

Proved developed reserves

Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved reserves

Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. 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 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. 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 twelve-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.

2


Proved undeveloped deserves ("PUDs")

Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Realized price

The cash market price, less all expected quality, transportation and demand adjustments.

Recompletion

The completion for production of an existing wellbore in another formation from that which the well has been previously completed. Reserves associated with recompletion are also referred to as “behind pipe.”

Reserves

Parts of mineral deposits which could be economically and legally extracted or produced at the time of the reserve determination.

Reservoir

A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

SEC

Securities and Exchange Commission.

Spacing

The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Spot price

The cash market price without reduction for expected quality, transportation and demand adjustments.

Standardized measure

The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Undeveloped acreage

Acreage owned or leased on which wells can be drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Unit

A contiguous geographic area that was established and approved by state oil and natural gas commissions for secondary recovery.

Unitization

The process of obtaining approval from working interest owners, mineral owners and regulatory agencies to conduct secondary (e.g., waterflooding) or tertiary operations.

Wellbore

The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

Working interest

The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover

Operations on a producing well to restore or increase production.

WTI

West Texas Intermediate, also called Texas light sweet, is a type of crude oil used as a benchmark in oil pricing. It is the underlying commodity of NYMEX’s oil future contracts.

3


NAMES OF ENTITIES

As used in this Form 10-K, unless we indicate otherwise:

 

Founders

collectively refers to Charles R. Olmstead, S. Craig George and Jeffrey R. Olmstead.

Our general partner

refers to Mid-Con Energy GP, LLC.

Mid-Con Affiliate

refers to Mid-Con Energy III, LLC, and its subsidiaries, which is an affiliate of our general partner.

ME3 Oilfield Service

refers to ME3 Oilfield Service, LLC, which is a wholly owned subsidiary of our Mid-Con Affiliate.

ME2 Well Services

refers to ME2 Well Services, LLC, which is an affiliate of our Mid-Con Affiliate and Mid-Con Energy Operating.

Mid-Con Energy Partners

the “partnership,” “we,” “our,” “us,” “company” or like terms when used refer to Mid-Con Energy Partners, LP, a Delaware limited partnership, and its subsidiaries.

Mid-Con Energy Operating

refers to Mid-Con Energy Operating, LLC, an affiliate of our general partner.

Mid-Con Energy Properties

refers to Mid-Con Energy Properties, LLC, our wholly owned subsidiary.

Our predecessor

collectively refers to Mid-Con Energy Corporation, prior to June 30, 2009, and to Mid-Con Energy I, LLC, and Mid-Con Energy II, LLC, on a combined basis, thereafter, our respective predecessors for accounting purposes.

Yorktown

collectively refers to Yorktown Partners, LLC, Yorktown Energy Partners VI, LP, Yorktown Energy Partners VII, LP, Yorktown Energy Partners VIII, LP, Yorktown Energy Partners IX, LP, and/or Yorktown Energy Partners X, LP.

4


FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (“Form 10-K”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (each a “forward–looking statement”). These forward–looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

volatility of commodity prices;

 

revisions to oil and natural gas reserves estimates as a result of changes in commodity prices;

 

effectiveness of risk management activities;

 

business strategies;

 

future financial and operating results;

 

our ability to pay distributions;

 

ability to replace the reserves we produce through acquisitions and the development of our properties;

 

future capital requirements and availability of financing;

 

technology;

 

realized oil and natural gas prices;

 

production volumes;

 

lease operating expenses;

 

general and administrative expenses;

 

cash flow and liquidity;

 

availability of production equipment;

 

availability of oil field labor;

 

capital expenditures;

 

availability and terms of capital;

 

marketing of oil and natural gas;

 

general economic conditions;

 

competition in the oil and natural gas industry;

 

environmental liabilities;

 

counterparty credit risk;

 

governmental regulation and taxation;

 

developments in oil producing and natural gas producing countries; and

 

plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this Annual Report on Form 10-K, are forward-looking statements. These forward-looking statements may be found in Item 1. “Business,” Item 1A. “Risk Factors,” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Annual Report on Form 10-K. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” “goal,” “forecast,” “guidance,” “might,” “scheduled” and the negative of such terms or other comparable terminology.

The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the forward-looking events will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in the “Risk Factors” section and elsewhere in this Annual Report on Form 10-K. All forward-looking statements speak only as of the date made, and other than as required by law, we do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

5


PART I

ITEM 1.

BUSINESS

Mid-Con Energy Partners, LP, is a publicly held Delaware limited partnership formed in July 2011 that engages in the ownership, acquisition and development of producing oil and natural gas properties in North America, with a focus on EOR. Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company. Our limited partner units (“common units”) are listed under the symbol “MCEP” on the NASDAQ.

Overview

We operate as one business segment engaged in the ownership, acquisition and development of producing oil and natural gas properties. As of December 31, 2017, our properties were located primarily in the Mid-Continent and Permian Basin regions of the United States in Oklahoma and Texas core areas. Our properties primarily consist of mature, legacy onshore oil reservoirs with long-lived, relatively predictable production profiles and low production decline rates.

Our management team has significant industry experience, especially with waterflood projects and, as a result, our operations focus primarily on enhancing the development of producing oil properties through waterflooding. Waterflooding, a form of secondary oil recovery, works by displacing or “sweeping” oil to producing wellbores. As of December 31, 2017, 64% of our net proved reserves were being produced under waterflood, on a Boe basis. Through the continued development of our existing properties and through future acquisitions, we seek to increase our reserves and production in order to make and, over time, increase distributions to our unitholders. In order to enhance the stability of our cash flow for the benefit of our unitholders, we generally hedge a portion of our production volumes through various commodity derivative contracts.

Our oil and natural gas production and reserve data as of December 31, 2017, were as follows:

 

we had total estimated proved reserves of 19.6 MMBoe, of which 95% were oil and 73% were proved developed;

 

we owned a working interest in 1,078 wells, all operated through our affiliate, Mid-Con Energy Operating;

 

average net production for the month ended December 31, 2017, was 4,502 gross (3,163 net) Boe/d; and

 

our total estimated proved reserves had an average reserve-to-production ratio of 17 years.

Our Business Strategies

The key elements of our business strategy are to:

 

maximize production and cash flows through continued development and operational efficiencies;

 

pursue acquisitions of long-lived, low-risk producing properties with upside potential; and

 

reduce the impact of commodity price volatility on our cash flows through a disciplined commodity hedging strategy.

Our Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective of generating and growing cash available for distribution:

 

an asset portfolio largely consisting of properties with existing waterflood projects with proved reserves, of which 95% are oil, and relatively predictable production profiles that provide growth potential through ongoing response to waterflooding and that have modest capital requirements;

 

the ability to further develop existing mature properties by utilizing our waterflood expertise;

 

acquisition opportunities that are consistent with our criteria of predictable production profiles with upside potential that may arise as a result of our relationship with the Mid-Con Affiliate;

 

access to the collective expertise of Yorktown’s employees and their extensive network of industry relationships through our relationship with Yorktown;

 

maintaining a high degree of operational control by operating a high percentage of our properties through our affiliate, Mid-Con Energy Operating, which allows them to control our operating costs and capital expenditures; and

 

the range and depth of our technical and operational expertise allows us to expand both geographically and operationally to achieve our goals.

6


Our Areas of Operations

As of December 31, 2017, our properties were primarily located in the Mid-Continent and Permian regions of the United States in Oklahoma and Texas core areas. These core areas are generally composed of multiple fields and waterflood units that are in close proximity to one another, produce from geologically similar reservoirs and utilize similar recovery methods. Focusing on these core areas allows us to apply our cumulative technical and operational knowledge to ongoing property development and to better predict future rates of recovery.

Oklahoma

Our Oklahoma properties are located in six counties in Oklahoma: Cleveland, Creek, Oklahoma, Osage, Pawnee and Seminole Counties. The majority of our Oklahoma properties are being produced under waterflood and are operated by Mid-Con Energy Operating. At December 31, 2017, our average working interest in these properties was 93%. During 2017, we drilled 3 gross producing wells, 1 gross injection well and converted 3 gross wells to injection.

Texas

Our Texas properties are located in eleven counties in Texas: Coke, Coleman, Fisher, Haskell, Jones, Kent, Liberty, Nolan, Runnels, Stonewall, and Taylor Counties. At December 31, 2017, we had an average working interest of approximately 95% in these properties. During 2017 we drilled 12 gross producing wells, 2 gross injection wells, 1 water supply well and converted 8 gross wells to injection wells.

The following table shows our estimated net proved reserves for our core areas, based on a reserve report prepared by our internal reserve engineers and audited by Cawley, Gillespie & Associates, Inc. (“CG&A”), our independent petroleum engineers, as of December 31, 2017:

 

 

 

Estimated Net Proved Reserves as of December 31, 2017

 

 

 

 

 

 

 

% of

Total

 

 

 

 

 

 

% Proved

 

 

Standardized Measure

 

Core Area

 

MBoe

 

 

Proved

Reserves

 

 

% Oil

 

 

Developed

Reserves

 

 

Amount (1)

($ in millions)

 

 

% of

Total

 

Oklahoma

 

 

12,218

 

 

 

62

%

 

 

96

%

 

 

78

%

 

$

108

 

 

 

52

%

Texas

 

 

7,339

 

 

 

38

%

 

 

92

%

 

 

65

%

 

$

99

 

 

 

48

%

Total

 

 

19,557

 

 

 

100

%

 

 

95

%

 

 

73

%

 

$

207

 

 

 

100

%

(1)

Our estimated net proved reserves and standardized measure were computed by applying average 12-month index prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the applicable 12-month period, held constant throughout the life of the properties). These prices were adjusted by lease for quality, transportation fees, location differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The average 12-month index prices were $51.34 per Bbl for oil and $2.98 per MMBtu for natural gas for the 12 months ended December 31, 2017.

Drilling Activities

The following table sets forth information with respect to drilling activities during the periods indicated. The information should not be considered indicative of future performance nor should a correlation be assumed between the numbers of productive wells drilled, quantities of reserves found or economic value.

 

 

 

Year Ended December 31,

 

 

 

2017

 

 

2016

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Developmental wells(1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

14

 

 

 

13

 

 

 

10

 

 

 

10

 

Injection

 

 

3

 

 

 

3

 

 

 

 

 

 

 

Water Supply

 

 

1

 

 

 

1

 

 

 

 

 

 

 

Dry

 

 

1

 

 

 

1

 

 

 

 

 

 

 

Total

 

 

19

 

 

 

18

 

 

 

10

 

 

 

10

 

(1) We did not drill any exploratory wells in 2017 or 2016.

7


Oil and Natural Gas Production, Revenue and Price History

The following table sets forth summary information regarding our historical production and operating data for the years ended December 31, 2017, and 2016. Due to normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

Production and Unit Costs per BOE

The following table provides net production volume data and average unit costs per BOE:

 

 

 

Year Ended December 31,

 

 

 

2017

 

 

2016

 

Production Volumes

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

1,209

 

 

 

1,386

 

Natural gas (MMcf)

 

 

431

 

 

 

554

 

Total (MBoe)

 

 

1,281

 

 

 

1,478

 

 

 

 

 

 

 

 

 

 

Average daily net production (Boe/d)

 

 

3,510

 

 

 

4,038

 

 

 

 

 

 

 

 

 

 

Average sales price

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

 

 

 

 

 

 

 

Sales price

 

$

47.72

 

 

$

39.52

 

Effect of net settlements on matured derivative

   instruments(1)

 

$

(3.64

)

 

$

8.40

 

Realized oil price after derivatives

 

$

44.08

 

 

$

47.92

 

Natural gas (per Mcf)

 

$

2.88

 

 

$

2.39

 

 

 

 

 

 

 

 

 

 

Average unit costs per Boe

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

16.87

 

 

$

15.35

 

Oil and natural gas production taxes

 

$

2.59

 

 

$

1.96

 

Depreciation, depletion and amortization

 

$

13.83

 

 

$

15.61

 

General and administrative expenses

 

$

4.46

 

 

$

4.66

 

(1) For the year ended December 31, 2017, effect of net settlements on matured derivative instruments does not include the $0.6 million received and the $1.1 million of deferred premiums paid upon early termination of previous oil derivative contracts in September and October 2017. For the year ended December 31, 2016, effect of net settlements on matured derivative instruments does not include the $5.8 million received and the $1.5 million of deferred premiums paid upon early termination of previous oil derivative contracts in July 2016 or the related $2.8 million premiums paid at inception of the oil derivative contracts in January 2015.

Production

The following table sets forth our production for the years ended December 31, 2017, and 2016, from our core areas:

 

 

 

Year Ended December 31,

 

 

 

2017

 

 

2016

 

 

 

Oil

 

 

Natural Gas

 

 

Oil

 

 

Natural Gas

 

Core Area

 

(MBbls)

 

 

(MMcf)

 

 

(MBbls)

 

 

(MMcf)

 

Oklahoma

 

 

686

 

 

 

159

 

 

 

732

 

 

 

134

 

Cleveland Field(1)

 

 

240

 

 

 

 

 

 

255

 

 

 

8

 

Creek County (Oilton)(1)

 

 

132

 

 

 

128

 

 

 

123

 

 

 

116

 

Texas

 

 

523

 

 

 

272

 

 

 

551

 

 

 

417

 

Hugoton(2)

 

 

 

 

 

 

 

 

103

 

 

 

3

 

Total

 

 

1,209

 

 

 

431

 

 

 

1,386

 

 

 

554

 

(1) Oklahoma includes production for the Cleveland and Creek County Fields, which are the only fields that represented 15% or more of our total estimated proved reserves at December 31, 2017, and 2016.

(2) Hugoton properties were divested on July 28, 2016 and included properties in Colorado, Oklahoma and Texas.

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Productive Wells

The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2017. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own a working interest, and net wells are the sum of our fractional working interests owned in gross wells.

 

 

 

Gross Wells

 

 

Net Wells

 

 

 

Oklahoma

 

 

Texas

 

 

Total

 

 

Oklahoma

 

 

Texas

 

 

Total

 

Oil

 

 

277

 

 

 

164

 

 

 

441

 

 

 

252

 

 

 

155

 

 

 

407

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Injection

 

 

105

 

 

 

48

 

 

 

153

 

 

 

94

 

 

 

45

 

 

 

139

 

Disposal

 

 

14

 

 

 

12

 

 

 

26

 

 

 

13

 

 

 

12

 

 

 

25

 

Water Supply

 

 

3

 

 

 

6

 

 

 

9

 

 

 

2

 

 

 

6

 

 

 

8

 

Shut-in or Waiting on Completion(1)

 

 

320

 

 

 

129

 

 

 

449

 

 

 

305

 

 

 

126

 

 

 

431

 

Total

 

 

719

 

 

 

359

 

 

 

1,078

 

 

 

666

 

 

 

344

 

 

 

1,010

 

(1) As of December 31, 2017, no wells were waiting on completion and no shut-in wells were associated with proved developed reserves. Only 12 shut-in wells were associated with PUDs and were currently scheduled for return to production as part of planned secondary recovery projects. No wells classified as shut-in were due to operational factors, such as awaiting pipeline or facilities connections.

Operations

General

We operate 100% of our properties, as calculated on a Boe basis as of December 31, 2017, through our affiliate, Mid-Con Energy Operating. We design and manage the development, recompletion or workover procedures for all of the wells we operate and supervise operation and maintenance activities. We do not own the drilling rigs or other oil field services equipment used for drilling or maintaining wells on the properties we operate.

We engage numerous independent contractors to provide all of the equipment and personnel associated with our drilling and maintenance activities, including well servicing, trucking, water hauling, bulldozing, and various downhole services (e.g., logging, cementing, perforating and acidizing). These services are short-term in duration (often being completed in less than a day) and are typically governed by a one-page service order that states only the parties’ names, a brief description of the services and the price.

We also engage several independent contractors to provide hydraulic fracturing services. These services are usually completed in four to six hours utilizing lower pressures and volumes of fluid than are typically employed in multi-stage hydraulic fracturing jobs performed in connection with unconventional oil and natural gas shale plays. These services are not normally governed by long-term services contracts, but instead are generally performed under one-time service orders, which state the parties’ name and the price. These service orders sometimes contain additional terms, for example, taxes, payment due dates, warranties and limitations of the contractor’s liability to damages arising from the contractor’s gross negligence or willful misconduct.

Geological and Engineering Services

Mid-Con Energy Operating employs production and reservoir engineers, geologists and land specialists, as well as field production supervisors. Through the services agreement, we have the direct operational support of a staff of approximately 20 petroleum professionals with significant technical expertise. We believe that this technical expertise, which includes extensive experience utilizing secondary recovery methods, particularly waterfloods, differentiates us from, and provides us with a competitive advantage over, many of our competitors. Please see Item 13. “Certain Relationships and Related Transactions, and Director Independence - Agreements and Transactions with Affiliates” for more information.

Administrative Services

Mid-Con Energy Operating provides us with management, administrative and operational services under the services agreement. We reimburse Mid-Con Energy Operating, on a cost basis, for the allocable expenses it incurs in performing these services. Mid-Con Energy Operating has substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. For a detailed description of the administrative services provided by Mid-Con Energy Operating pursuant to the services agreement, please see Item 13. “Certain Relationships and Related Transactions, and Director Independence - Agreements and Transactions with Affiliates.”

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Oil and Natural Gas Leases

The typical oil lease agreement covering our properties provides for the payment of royalties to the mineral owner for all hydrocarbons produced from any well drilled on the lease premises. As of December 31, 2017, the lessor royalties and other leasehold burdens on our properties ranged from less than 12.5% to 38.7%, resulting in a net revenue interest to us ranging from 61.3% to 87.5% on a 100%, working interest basis, and our average net revenue interest is 76.3%. Generally, most of our leases are held by production and do not require lease rental payments.

Principal Customers

For the year ended December 31, 2017, sales of oil and natural gas to four purchasers accounted for 99% of our sales. The loss of any of our customers could temporarily delay production and sale of our oil and natural gas. If we were to lose any of our significant customers, we believe we could identify substitute customers to purchase the impacted production volumes. However, if any of our customers dramatically decreased or ceased purchasing oil from us, we may experience difficulty receiving comparable rates for our production volumes.

Delivery Commitments

We have no commitments to deliver a fixed and determinable quantity of our oil or natural gas production in the near future under our existing contracts.

Hedging Activities

We continue to enter into commodity derivative contracts with unaffiliated third parties that are also members of our banking group to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and natural gas prices. At December 31, 2017, our commodity derivative contracts had maturities through 2019 and were comprised of price swaps, puts and collars. For a more detailed discussion of our hedging activities, see Note 5 to the Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data.”

Competition

We operate in a highly competitive environment for acquiring properties and securing trained personnel. Many of our competitors possess and employ financial resources substantially greater than ours, which can be particularly important in the areas in which we operate. These companies may have a greater ability to continue acquisition, and or exploration and production activities during periods of low commodity prices. Some of our competitors may also possess greater technical and personnel resources than us. As a result, our competitors may be able to pay more for properties, as well as evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry.

At times, we may also be affected by competition for drilling rigs, completion rigs and the availability of related equipment and services. In times past, the U.S. onshore oil and natural gas industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which have delayed development drilling and caused significant increases in the price for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our development program.

Insurance

In accordance with industry practice, we maintain insurance against many potential operating risks to which our business could be exposed. Our coverage includes general liability, commercial umbrella liability, control of well, auto liability, property and equipment, worker’s compensation and employer’s liability, and directors and officer’s liability.

Currently, we have coverage for general liability insurance coverage, which includes coverage for sudden and accidental pollution liability and legal and contractual liabilities arising out of property damage and bodily injury, among other things. The insurance policies contain maximum policy limits and in most cases, deductibles that must be met prior to recovery and are subject to certain customary exclusions and limitations. This insurance coverage is in addition to the general and automobile liability policies and may be triggered if the general or automobile liability insurance policy limits are exceeded and exhausted. The control of well policy insures us for blowout risks associated with drilling, completing and operating our wells, including above ground pollution.

These policies do not provide coverage for all liabilities, and no assurance can be given that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

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Environmental Matters and Regulation

General

Our operations are subject to stringent and complex federal, tribal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things (i) require the acquisition of permits to conduct exploration, drilling and production operations; (ii) govern the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with drilling and production activities; (iii) restrict the way we handle or dispose of our wastes; (iv) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (v) require investigatory and remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and (vi) impose obligations to reclaim and abandon wellsites. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of corrective or remedial obligations, and the issuance of orders enjoining performance of some or all of our operations.

These laws and regulations may also restrict the rate of production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the U.S. Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, storage, transport, drilling, disposal, and remediation requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, drilling, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot provide assurances that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, we can provide no assurance that we will not incur substantial costs in the future related to revised or additional environmental regulations that could have a material adverse effect on our business, financial condition and results of operations.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste

The federal Resource Conservation and Recovery Act, as amended, (“RCRA”), and comparable state statutes and their respective implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil, if properly handled, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. However, it is possible that certain oil exploration, development and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to public health or the environment and to seek to recover from responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances or other pollutants released into the environment. Despite the so-called petroleum exclusion, we generate materials in the course of our operations that may be regulated as hazardous substances.

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We currently own and lease numerous properties that have been used for oil and/or natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination.

Water Discharges

The federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws, impose restrictions and strict controls regarding the discharge of pollutants, including oil and hazardous substances, into state waters and federal navigable U.S. waters The discharge of pollutants into federal or state waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state or tribal agency that has been delegated authority for the program by the EPA. Federal, state and tribal regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws required individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

The Oil Pollution Act of 1990, as amended (“OPA”), amends the Clean Water Act and establishes strict liability for owners and operators of facilities that are the site of a release of oil into U.S. waters The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the United States.

The Safe Drinking Water Act, as amended, (“SDWA”) and analogous state laws impose requirements relating to our underground injection activities. Under these laws, the EPA and state environmental agencies have adopted regulations related to permitting, testing, monitoring, record-keeping and reporting of injection well activities, as well as prohibitions against the migration of injected fluids into underground sources of drinking water. We currently own a number of injection wells, used primarily for reinjection of produced waters that are subject to SDWA requirements.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We employ conventional hydraulic fracturing techniques to increase the productivity of certain of our properties. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into rock formations to fracture the surrounding rock and stimulate production. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the SDWA and has published guidance documents related to this regulatory authority. In addition, from time to time, Congress has considered federal regulation of hydraulic fracturing including disclosure of the chemicals used in the hydraulic fracturing process. Several states in which we operate, including Texas and Oklahoma, have adopted rules requiring the disclosure of certain information related to hydraulic fluids associated with wells that are hydraulically fractured. Additionally, some states and local governments have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, the State of Oklahoma has issued directives to shut-in or reduce the volume sent to disposal wells in the areas that have experienced recent earthquake activity. Other authorities are considering restrictions on the disposal of hydraulic fluids by deep well injection. We follow applicable industry standard practices and legal requirements for groundwater protection in our hydraulic fracturing activities. In the event that new or more stringent federal, state or local legal restrictions are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities.

There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has completed a study of the potential environmental effects of hydraulic fracturing on drinking water resources and issued its final report in December 2016. The report concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances and identified conditions under which such impacts can be more frequent or severe. In June 2016, the EPA published final pretreatment standards for oil and natural gas extraction to ensure that wastewater from hydraulic fracturing activities is not sent to publicly owned treatment works. Subsequent rules have extended the implementation date for certain facilities that are subject to these standards. The U.S. Department of Energy is conducting an

12


investigation of practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. More recently, there have been reports linking the injection of produced fluids from hydraulic fracturing to earthquakes. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

Almost all of our hydraulic fracturing operations are conducted on vertical wells. The fracture treatments on these wells are much smaller and utilize much less water than what is typically used on most of the shale oil and natural gas wells that are being drilled throughout the United States. The majority of our leasehold acreage is currently held by production from existing wells. Therefore, fracturing is not currently required to maintain this acreage but it will be required in the future to develop the majority of our proved behind pipe and proved undeveloped reserves associated with this acreage.

We follow applicable industry standard practices and legal requirements for groundwater protection in our operations, subject to close supervision by state and federal regulators, which conduct many inspections during operations that include hydraulic fracturing. We minimize the use of water and dispose of the produced water into approved disposal or injection wells. We currently do not intentionally discharge water to the surface.

Air Emissions

The federal Clean Air Act, as amended, and comparable state laws regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay the development of our projects.

While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues, we do not believe that such requirements will have a material adverse effect on our operations. For example, on August 16, 2012, the EPA published final regulations under the Clean Air Act that, among other things, required additional emissions controls for natural gas and NGLs production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOC”), and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations required the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations that occurred at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also established specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. Compliance with these requirements could increase our costs of development and production, though we do not expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

Climate Change

In December 2009, the EPA published its findings that emissions of carbon dioxide, or CO2, methane, and other greenhouse gases, or “GHG”, present a danger to public health and the environment. Based on these findings, the EPA began adopting and implementing regulations that restrict emissions of GHG under existing provisions of the federal Clean Air Act. These regulations include requirements to regulate emissions of GHG from motor vehicles, certain requirements for construction and operating permit reviews for GHG emissions from certain large stationary sources, rules requiring the reporting of GHG emissions from specified large GHG emission sources including operators of onshore oil and natural gas production and rules requiring so-called green completions of natural gas wells for wells constructed after January 2015. In addition, in May 2016, the EPA issued new regulations that set methane and VOC emission standards for certain oil and natural gas facilities. In July 2017, the EPA proposed a two-year study of certain requirements of this rule pending reconsideration of the rule. The Paris Agreement, which was created by the United Nations Framework Convention on Climate Change, entered into force on November 4, 2016. The Paris Agreement requires participating countries to establish “nationally determined contributions” to mitigate climate change that “represent a progression over time” and are reported at five-year intervals. The United States announced its intention to withdraw from the Paris Agreement on June 1, 2017.

We are currently monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule. Data collected from our initial GHG monitoring activities indicated that we do not currently exceed the threshold level of GHG emissions triggering a reporting obligation. To the extent we exceed the applicable regulatory threshold level in the future, we will report the emissions beginning in the applicable period. Also, the U.S. Congress has from time to time considered legislation to reduce emissions of GHG and almost one-half of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHG. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require us to incur significant costs to reduce emissions of GHG associated with operations or could adversely affect demand for our production.

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The EPA has also finalized regulations to reduce carbon dioxide emissions from the utility power sector, commonly referred to as the Clean Power Plan, which, if implemented, could reduce the demand for fossil fuels. The implementation of this rule has been stayed pending judicial review, and in October 2017, the EPA proposed the repeal of the Clean Power Plan.

National Environmental Policy Act

Oil exploration, development and production activities that are located on federal lands or have a federal “nexus” are subject to the National Environmental Policy Act, as amended, (“NEPA”). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that analyzes the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. Future or proposed exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA may be required. This process has the potential to delay the development of oil projects.

Endangered Species Act

The federal Endangered Species Act (“ESA”) may restrict activities that affect endangered or threatened species. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. The designation of previously unidentified endangered or threatened species habitats could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act over a period of six years. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

OSHA

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, (“OSHA”), and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes and regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Other Regulation of the Oil and Natural Gas Industry

General

Various aspects of our oil and natural gas operations are subject to extensive and frequently changing regulation as the activities of the oil and natural gas industry often are reviewed by legislators and regulators. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members.

The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. FERC regulates interstate oil pipelines under the provisions of the Interstate Commerce Act (“ICA”) as in effect in 1977 when ICA jurisdiction over oil pipelines was transferred to FERC, and the Energy Policy Act of 1992, or the EPA Act 1992. FERC is also authorized to prevent and sanction market manipulation in natural gas markets under the Energy Policy Act of 2005. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas, effective January 1, 1993. While sales by producers of natural gas and all sales of crude oil, condensate and NGLs can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

In addition, the Federal Trade Commission (“FTC”), and the U.S. Commodity Futures Trading Commission (“CFTC”) hold statutory authority to prevent market manipulation in oil and energy futures markets, respectively. Together with FERC, these agencies have imposed broad rules and regulations prohibiting fraud and manipulation in oil and natural gas markets and energy futures markets. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation. Failure to comply with such market rules, regulations and requirements could have a material adverse effect on our business, results of operations, and financial condition.

14


Oil and NGLs Transportation Rates

Our sales of crude oil, condensate and NGLs are not currently regulated and are transacted at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the ICA and EPA act 1992. The price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market. Interstate transportation rates for oil, NGLs, and other products are regulated by the FERC, and in general, these rates must be cost-based or based on rates in effect in 1992, although FERC has established an indexing system for such transportation which allows such pipelines to take an annual inflation-based rate increase. Shippers may, however, contest rates that do not reflect costs of service. The FERC has also established market-based rates and settlement rates as alternative forms of ratemaking in certain circumstances.

In other instances involving intrastate-only transportation of oil, NGLs, and other products, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. Such pipelines may be subject to regulation by state regulatory agencies with respect to safety, rates and/or terms and conditions of service, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for intrastate regulation and the degree of regulatory oversight and scrutiny given to intrastate pipelines varies from state to state. Many states operate on a complaint-based system and state commissions have generally not initiated investigations of the rates or practices of liquids pipelines in the absence of a complaint.

Regulation of Oil and Natural Gas Exploration and Production

Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the location of wells, the method of drilling, casing, operating, plugging and abandoning wells, notice to surface owners and other third parties, and governing the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation of oil and natural gas resources, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing of such wells.

Oklahoma allows forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil wells generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill.

States also impose severance taxes and enforce requirements for obtaining drilling permits. For example, the State of Oklahoma currently imposes a production tax and an excise tax for oil and natural gas properties. Additionally, production tax rates vary by state. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future.

There are constantly numerous new and proposed regulations related to oil and natural gas exploration and production activities. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Pipeline Safety

While we do not own pipelines subject to safety regulation, we rely on such pipelines to deliver our production. Federal and state safety regulations have become increasingly more stringent over time and could affect the availability and cost of pipeline transportation to us.

Employees

The officers of our general partner manage our operations and activities. Neither we, our subsidiaries, nor our general partner have employees. Our general partner has entered into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating will perform services for us, including the operation of our properties. Mid-Con Energy Operating has over 70 employees performing services for our operations and activities. We believe that Mid-Con Energy Operating has a satisfactory relationship with these employees.

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Offices

In addition to our oil and natural gas properties discussed above, we lease corporate office space in Tulsa, Oklahoma, and lease field office space in Abilene, Texas. Our affiliate, Mid-Con Energy Operating, maintains a number of field office locations. We believe that our existing office facilities are adequate to meet our needs for the immediate future.

Financial Information

We operate our business as a single segment. Additionally, all of our properties are located in the United States and all of the related reserves are derived from properties located in the United States. Our financial information is included in the consolidated financial statements and the related notes included in Item 8. “Financial Statements and Supplementary Data.”

Available Information

Our annual reports on Form 10–K, quarterly reports on Form 10–Q, current reports on Form 8–K 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, are made available free of charge on our website at www.midconenergypartners.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. These documents are also available on the SEC’s website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC, 20549. No information from either the SEC’s website or our website is incorporated herein by reference.

 

 

ITEM 1A.

RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. This list is not exhaustive.

Risks Related to Our Business

We may not have sufficient cash available to make quarterly distributions on our units following the establishment of cash reserves and payment of expenses, including payments to our general partner.

In October 2015, the Board elected to suspend quarterly cash distributions on our common units and the terms of our revolving credit facility require the pre-approval of our lenders before we resume making distributions. The Board may not elect to resume the quarterly distributions on our common units, but if they do, we may not have sufficient cash available to continue to make quarterly distributions on our common units. Under the terms of our Partnership Agreement, the amount of cash available for distributions will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including development of our oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders. The amount of cash that we distribute to our unitholders will depend principally on the cash we generate from operations, which will depend on, among other factors:

 

the amount of oil and natural gas we produce;

 

 

the prices at which we sell our oil and natural gas production inclusive of the net revenues from realized hedges;

 

 

the amount and timing of settlements on our commodity derivative contracts;

 

 

the ability to acquire additional oil and natural gas properties on economically acceptable terms;

 

 

the ability to continue our development projects at economically attractive costs;

 

 

the level of our capital expenditures, including scheduled and unexpected maintenance expenditures;

 

 

the level of our operating costs, including payments to our general partner; and

 

 

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

Our Partnership Agreement also prevents us from declaring or making any distributions on our common units if we fail to pay any Class A Preferred Unit or Class B Preferred Unit distribution in full on the applicable payment date, until such time as all accrued and unpaid Class A Preferred Unit and Class B Preferred Unit distributions have been paid in full in cash.

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If we do not maintain certain financial covenants under our revolving credit facility we may be deemed in breach, entitling our lenders to accelerate the amounts due under the facility or foreclose on our properties.

We are dependent on our revolving credit facility, and a change in a number of financial and operating factors that can materially influence the cash flow generation of our business, including but not limited to, future oil and natural gas prices, sales from produced oil and natural gas volumes, and cash operating expenses, could result in our breaching certain financial covenants under the revolving credit facility, which would constitute a default under the revolving credit facility. Such default, if not cured, would require a waiver from our lenders to avoid an event of default and, subject to certain limitations, subsequent acceleration of all amounts outstanding under the revolving credit facility and potential foreclosure on our oil and natural gas properties.

At the quarter ended September 30, 2017, we were not in compliance with our leverage calculation ratio. Although we subsequently received a waiver from the Administrative Agent and the Lenders under our revolving credit facility and are now in compliance with the leverage calculation ratio, there can be no assurances that we will remain in compliance with the leverage calculation ratio or any other ratios in the future, or that we will receive another waiver should we fail to satisfy a covenant again.

If oil prices decline from current levels, or if there is an increase in the differential between the NYMEX-WTI or other benchmark prices of oil and the wellhead price we receive for our production, our cash flows from operations will decline.

Lower oil prices may decrease our revenues and therefore, our cash flows from operations. Prices for oil may fluctuate widely in response to relatively minor changes in supply of and demand for oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

the domestic and foreign supply of and demand for oil;

 

market expectations about future prices of oil;

 

the price and quantity of imports of crude oil;

 

overall domestic and global economic conditions;

 

political and economic conditions in other oil producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;

 

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

 

trading in oil derivative contracts;

 

the level of consumer product demand;

 

weather conditions and natural disasters;

 

technological advances affecting energy consumption;

 

domestic and foreign governmental regulations and taxes;

 

the proximity, cost, availability and capacity of oil pipelines and other transportation facilities;

 

the impact of the U.S. dollar exchange rates on oil prices; and

 

the price and availability of alternative fuels.

Also, the prices that we receive for our oil production often reflect a regional discount, based on the location of the production, to the relevant benchmark prices, such as the NYMEX-WTI, that are used for calculating hedge positions. These discounts, if significant, could similarly adversely affect our cash flows from operations and financial condition.

In the past, we have raised our distribution levels on our common units in response to increased cash flow during periods of relatively high commodity prices. However, we have not been able to sustain those distributions. In October 2015, the Board elected to suspend quarterly cash distributions on our common units. There is no guarantee that we will reinstate distributions on our common units in the near future.

Volatile oil prices may significantly impact our business.

Historically, oil prices have been extremely volatile. For the five years ended December 31, 2017, front-month NYMEX-WTI oil futures prices ranged from a high of $110.53 per barrel to a low of $26.21 per barrel. The volatility of the energy markets make it extremely difficult to predict future oil price movements with any certainty.

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If commodity prices decline from current levels, production from some of our producing or development projects may become uneconomic and cause write downs of the value of our properties, which may adversely affect our financial condition and our ability to make distributions to our unitholders.

If commodity prices decline from current levels, some of our producing or development projects may become uneconomic and, if the decline is severe or prolonged, a significant portion of such projects may become uneconomic. As producing or development projects become uneconomic, our reserve estimates will be adjusted downward, which could negatively impact our borrowing base under our current revolving credit facility and our ability to fund our operations.

Deteriorating commodity prices may cause us to recognize impairments in the value of our oil and natural gas properties. We recognized $25.0 million in non-cash impairment expense for the year ended December 31, 2017. In addition, 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 additional impairments. We may incur impairment in the future which could have a material adverse effect on our results of operations in the period taken.

Our hedging strategy may be ineffective in mitigating the impact of commodity price volatility on our cash flows, which could adversely affect our financial condition.

Our hedging strategy is to enter into commodity derivative contracts covering a portion of our near-term estimated oil production. The prices at which we are able to enter into commodity derivative contracts covering our production in the future will be dependent upon oil futures prices at the time we enter into these transactions, which may be substantially higher or lower than current oil prices.

Our revolving credit facility prohibits us from entering into commodity derivative contracts with the purpose and effect of fixing prices covering all of our estimated future production, and we therefore retain the risk of a price decrease on our volumes which we are precluded from securing with commodity derivative contracts. Furthermore, we may be unable to enter into additional commodity derivative contracts during favorable market conditions and, thus, may be unable to lock in attractive future prices for our product sales. Finally, our revolving credit facility and associated amendments may cause us to enter into commodity derivative contracts at inopportune times.

Our hedging activities could result in cash losses and may limit the prices we would otherwise realize for our production, which could reduce our cash flows from operation.

Our hedging strategy may limit our ability to realize cash flows from commodity price increases. Many of our commodity derivative contracts require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays), we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially adversely impact our liquidity, financial condition and cash flows from operations.

Our hedging transactions expose us to counterparty credit risk and involve other risks.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a commodity derivative contract. Disruptions in the financial markets could lead to a sudden decrease in a counterparty’s liquidity, which could impair its ability to perform under the terms of the commodity derivative contract and, accordingly, prevent us from realizing the benefit of the commodity derivative contract. Because we conduct our hedging activities exclusively with participants in our revolving credit facility, our net position on a counterparty by counterparty basis is generally that of a borrower.

As a result of the Dodd-Frank Wall Street Reform and Consumer Protection Act and other legislation, hedging transactions and many of our contract counterparties have come under increasing governmental oversight and regulations in recent years. Although we cannot predict the ultimate impact of these laws and the related rulemaking, some of which is ongoing, existing or future regulations may adversely affect the cost and availability of our hedging arrangements, including by causing our counterparties, which include lenders under our revolving credit facility, to curtail or cease their derivative activities.

Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flows from operations.

Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production and, therefore, our cash flows from operations and ability to resume making distributions on our common units are highly dependent on our success in economically finding or acquiring recoverable reserves and efficiently developing our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we make acquisitions. We

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may not be able to develop, find or acquire additional reserves to replace our current and future production on economically acceptable terms, which would adversely affect our business, financial condition and results of operations.

Our business requires significant capital expenditures, and we may be unable to obtain needed capital or financing on satisfactory terms or at all.

We make, and expect to continue to make, substantial capital expenditures for the development, production and acquisition of oil and natural gas reserves. We do not expect to fund all of these expenditures with cash flows from operations and, if additional capital is needed, we may not be able to obtain debt or equity financing on attractive terms or at all, due to lower oil and natural gas prices, declines in our estimated reserves or production or for any other reason. If cash generated by operations or availability under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to advancement of our development projects, which in turn could lead to a decline in our oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.

Developing and producing oil and natural gas is a costly and high-risk activity with many uncertainties that could adversely affect our business activities, financial condition or results of operations.

The cost of developing and operating oil and natural gas properties, particularly under a waterflood, is often uncertain, and cost and timing factors can adversely affect the economics of a well. Our efforts may be uneconomical if we drill dry holes, or if our properties are productive but do not produce as much oil or natural gas as we had estimated. Furthermore, our producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

high costs, shortages or delivery delays of equipment, labor or other services;

 

unexpected operational events and conditions;

 

adverse weather conditions and natural disasters;

 

injection plant or other facility or equipment malfunctions and equipment failures or accidents;

 

title disputes;

 

unitization difficulties;

 

pipe or cement failures, casing collapses or other downhole failures;

 

compliance with environmental and other governmental requirements;

 

lost or damaged oilfield service tools;

 

unusual or unexpected geological formations and reservoir pressure;

 

loss of injection fluid circulation;

 

restrictions in access to, or disposal of, water used or produced in drilling, completions and waterflood operations;

 

costs or delays imposed by or resulting from compliance with regulatory requirements;

 

fires, blowouts, surface craterings, explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations; and

 

uncontrollable flows of oil or well fluids.

If any of these factors were to occur with respect to a particular property, we could lose all or a part of our investment in the property, or we could fail to realize the expected benefits from the property, either of which could materially and adversely affect our financial condition or results of operations.

We inject water into most of our properties to maintain and, in some instances, to increase the production of oil and natural gas. In the future we may employ other secondary or tertiary recovery methods in our operations. The additional production and reserves attributable to the use of secondary recovery methods and of tertiary recovery methods are inherently difficult to predict. If our recovery methods do not result in expected production levels, we may not realize an acceptable return on the investments we make to use such methods.

Hydraulic fracturing has been a part of the completion process for the majority of the wells on our producing properties, and most of our properties are dependent on our ability to hydraulically fracture the producing formations. We engage third-party contractors to provide hydraulic fracturing services and generally enter into service orders on a job-by-job basis. Some service orders limit the liability of these contractors. Hydraulic fracturing operations can result in surface spillage or, in rare cases, the underground migration of fracturing fluids. Any such spillage or migration could result in litigation, government fines and penalties or remediation or restoration obligations. Our current insurance policies provide some coverage for losses arising out of our hydraulic fracturing operations. However,

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these policies may not cover fines, penalties or costs and expenses related to government-mandated cleanup activities, and total losses related to a spill or migration could exceed our per occurrence or aggregate policy limits. Any losses due to hydraulic fracturing that are not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.

It is not possible to measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering is complex, requiring subjective estimates of underground accumulations of oil and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may prove inaccurate. For example, if the price used in our December 2017 reserve report had been $10.00 less per barrel for oil, then the standardized measure of our estimated proved reserves as of that date would have decreased from $207.2 million to $131.4 million.

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could affect our business, results of operations and financial condition and our ability to make distributions to our unitholders.

The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil reserves.

The present value of future net cash flows from our proved reserves, or standardized measure, may not represent the current market value of our estimated proved oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our estimated proved reserves on the 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities-Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations.

One of our growth strategies is to capitalize on opportunistic acquisitions of oil reserves. We may not achieve the expected results of any acquisition we complete, and any adverse conditions or developments related to any such acquisition may have a negative impact on our operations and financial condition. Any acquisition involves potential risks, including, among other things:

 

the validity of our assumptions about estimated proved reserves, future production, commodity prices, revenues, operating expenses and costs;

 

an inability to successfully integrate the assets we acquire;

 

a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

 

a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

 

the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

 

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

 

an inability to hire, train or retain qualified personnel to manage and operate our growing assets; and

 

the occurrence of other significant charges, such as the impairment of oil properties, goodwill or other intangible assets, asset devaluations or restructuring charges.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often inconclusive and subject to various interpretations.

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Also, our reviews of properties acquired from third parties (as opposed to the Mid-Con Affiliate) may be incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition, given the time constraints imposed by most sellers. Even a detailed review of the properties owned by third parties and the records associated with such properties may not reveal existing or potential problems, nor will such a review permit us to become sufficiently familiar with such properties to assess fully the deficiencies and potential issues associated with such properties. We may not always be able to inspect every well on properties owned by third parties, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.

Adverse developments in our core areas would reduce our ability to make distributions to our unitholders.

We only own oil and natural gas properties and related assets, all of which are currently located in Oklahoma, Texas and Wyoming. An adverse development in the oil and natural gas business in these geographic areas could have an impact on our business, financial condition and results of operations.

We are primarily dependent upon a small number of customers for our production sales and we may experience a temporary decline in revenues and production if we lose any of those customers.

The loss of any of our customers could temporarily delay production and sale of our oil and natural gas. If we were to lose any of our significant customers, we believe that we could identify substitute customers to purchase the impacted production volumes. However, if any of our customers dramatically decreased or ceased purchasing oil from us, we may have difficulty receiving comparable rates for our production volumes.

Sales of oil and natural gas to four purchasers accounted for 99% of our sales for the year ended December 31, 2017. Our production is, and will continue to be, marketed by our affiliate, Mid-Con Energy Operating. By selling a substantial majority of our current production to a small concentration of customers we believe that we have obtained and will continue to receive more favorable pricing than would otherwise be available to us if smaller amounts had been sold to several purchasers based on posted prices. To the extent these significant customers reduce the volume of oil and natural gas they purchase from us, we could experience a temporary interruption in sales of, or may receive a lower price for, our production, and our revenues and cash flows from operations could decline which could adversely affect our financial condition and results of operations.

In addition, a failure by any of these significant customers, or any purchasers of our production, to perform their payment obligations to us could have a material adverse effect on our results of operations. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and ability to make distributions to our unitholders.

Unitization difficulties may prevent us from developing certain properties or greatly increase the cost of their development.

Typical regulatory requirements for waterflood unit formation require anywhere from 63% to 85% of the leasehold and mineral owners in a proposed unit area to consent to a unitization plan before the relevant regulatory body will issue a unitization order. Mid-Con Energy Operating may be required to dedicate significant amounts of time and financial resources to obtaining consents from other owners and the necessary approvals from the state and federal regulatory agencies. These consents and approvals may also delay our ability to begin developing our new waterflood projects and may prevent us from developing our properties in the way we desire.

Other owners of mineral rights may object to our waterfloods.

It is difficult to predict the movement of the injection fluids that we use in connection with waterflooding. It is possible that certain of these fluids may migrate out of our areas of operations and into neighboring properties, including properties whose mineral rights owners have not consented to participate in our operations. This may result in litigation in which the owners of these neighboring properties may allege, among other things, a trespass and may seek monetary damages and possibly injunctive relief, which could delay or even permanently halt our development of certain of our oil properties.

We might be unable to compete effectively with larger companies, which might adversely affect our business activities, financial condition and results of operations.

The oil and natural gas industry is intensely competitive, and we compete with companies that possess and employ financial, technical and personnel resources substantially greater than ours. These companies may be able to pay more for properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and

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natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities despite the currently depressed oil price environment and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

Many of our leases are in areas that have been partially depleted or drained by offset wells.

Many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests lying contiguous or adjacent to or adjoining our interests could take actions, such as drilling additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further develop our reserves.

Our revolving credit facility has restrictions and financial covenants that may restrict our business and financing activities, and the pre-approval of our lenders will be required for us to resume distributions on our common units.

Our revolving credit facility also restricts, among other things, our ability to incur debt and pay distributions under certain circumstances, and requires us to comply with customary financial covenants and specified financial ratios. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our revolving credit facility that are not cured or waived within specific time periods, a significant portion of our indebtedness may become immediately due and payable, we could be prohibited from making distributions to our unitholders in the future, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets. Further, the terms of our credit agreement require the pre-approval of our lenders in order to reinstate distributions on our common units.

The total amount we are able to borrow under our revolving credit facility is limited by a borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts, as determined by our lenders in their sole discretion. The borrowing base is subject to redetermination on a semi-annual basis and more frequent redetermination in certain circumstances. If our lenders were to decrease our borrowing base to a level below our then outstanding borrowings, the amount exceeding the revised borrowing base could become immediately due and payable. The negative redetermination of our borrowing base could adversely affect our business, results of operations, financial condition and our ability to make distributions to our unitholders. Furthermore, in the future, we may be unable to access sufficient capital under our revolving credit facility as a result of any decrease in our borrowing base.

We may not be able to generate enough cash flows to meet our debt obligations.

We expect our earnings and cash flows to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Additionally, our future cash flows may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flows from operations and to service our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

If we do not generate enough cash flows from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

 

refinancing or restructuring our debt;

 

selling assets;

 

reducing or delaying capital investments; or

 

seeking to raise additional capital.

However, we cannot provide assurances that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flows to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our ability to service our indebtedness and our business, financial condition and results of operations.

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Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

There are a variety of operating risks inherent in the exploration, development and production of our oil and natural gas properties, such as leaks, explosions, mechanical problems and natural disasters, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses. The location of our wells and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.

Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. 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. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to weather and adverse economic conditions have made it more difficult for us to obtain certain types of coverage. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and we cannot be sure the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and under-insured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.

Our business depends in part on transportation, pipelines and refining facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our production and could harm our business.

The marketability of our production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods, and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on such systems, tanker truck availability and extreme weather conditions. Also, the shipment of our oil on third party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or refining facility capacity could reduce our ability to market our oil production and harm our business. Our access to transportation options and the prices we receive for our production can also be affected by federal and state regulation, including regulation of oil production and transportation, and pipeline safety, as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHG present a danger to public health and the environment. Based on these findings, the EPA began adopting and implementing regulations that restrict emissions of GHG under existing provisions of the federal Clean Air Act, including requirements to reduce emissions of GHG from motor vehicles, requirements associated with certain construction and operating permit reviews for GHG emissions from certain large stationary sources, reporting requirements for GHG emissions from specified large GHG emission sources, including certain owners and operators of onshore oil and natural gas production and rules requiring so-called “green completions” of natural gas wells constructed after January 2015. We are currently monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule. Data collected from our initial GHG monitoring activities indicated that we do not exceed the threshold level of GHG emissions triggering a reporting obligation. To the extent we exceed the applicable regulatory threshold level in the future, we will report the emissions beginning in the applicable period. Also, the U.S. Congress has from time to time considered legislation to reduce emissions of GHG, and almost one-half of the states, either individually or through multi-state regional initiatives, have already begun implementing legal measures to reduce emissions of GHG. In March 2016, the EPA issued new regulations that set methane and VOC emission standards for certain oil and natural gas facilities. In July 2017, the EPA proposed a two-year stay of certain requirements of this rule pending reconsideration of the rule. In addition, under the Paris Agreement, which went into effect on November 4, 2016, the United States is required to establish increasingly stringent nationally determined contributions to mitigate climate change. The United States announced its intention to withdraw from the Paris Agreement on June 1, 2017. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require us to incur significant costs to reduce emissions of GHG associated with operations or could adversely affect demand for our production.

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Regulation in response to seismic activity could increase our operating and compliance costs.

Recent earthquakes in northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. To date, these regulations have not adversely impacted our operations but could limit future development for our operations. The adoption and implementation of any new laws, rules, regulations, requests, or directives that restrict our ability to dispose of water, including by plugging back the depths of disposal wells, reducing the volume of oil and natural gas wastewater disposed in such wells, restricting disposal well locations, or by requiring us to shut down disposal wells, could have a material adverse effect on our ability to produce oil and natural gas economically, or at all, and accordingly, could materially and adversely affect our business, financial condition and results of operations.

Rules recently finalized regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs.

In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA’s final rule includes NSPS standards for completions of hydraulically fractured wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The new rules became effective October 15, 2012; however, a number of the requirements did not take immediate effect as the final rule establishes a phase-in period to allow for the manufacture and distribution of required emissions reduction technology. As an example, until December 31, 2014, owners and operators of hydraulically fractured gas wells could either flare their emissions or use emissions reduction technology called “green completions” technologies already deployed at wells. On or after January 1, 2015, all newly fractured wells were required to use green completions. Controls for certain storage vessels, pneumatic controllers, compressors, dehydrators and other equipment must be implemented immediately or phased-in over time, depending on the construction date and/or nature of the unit. Compliance with these requirements could increase our costs of development and production, though we do not expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil development and production activities. These costs and liabilities could arise under a wide range of federal, state, tribal and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. Claims for damages to persons or property from private parties and governmental authorities may result from environmental and other impacts of our operations.

Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to make cash distributions to our unitholders could be adversely affected. For a detailed discussion please read Item 1. “Business - Environmental Matters and Regulation.”

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used in the completion of unconventional wells in shale formations as well as tight conventional formations, including many of those that we complete and produce. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act and has published guidance documents related to this regulatory authority. In addition, from time to time, Congress has considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Many states in which we operate have adopted rules requiring well operators to publicly disclose certain information regarding hydraulic fracturing operations, including the chemical composition of any liquids used in the hydraulic fracturing process. Generally, certain proprietary information may be excluded from an operator’s disclosure. Additionally, some states and local authorities have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. In the event that

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new or more stringent federal, state or local legal restrictions are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in our development or production activities.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has completed a study of the potential environmental effects of hydraulic fracturing on drinking water resources and issued its final report in December 2016. The report concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances and identified conditions under which the impacts may be more frequent or severe. In June 2016, the EPA published final pretreatment standards for oil and gas extraction sources to ensure that wastewater from hydraulic fracturing activities is not sent to publicly owned treatment works. Subsequent rules have extended the implementation date for certain facilities that are subject to these standards. The U.S. Department of Energy is conducting an investigation of practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. More recently, there have been reports linking the injection of produced fluids from hydraulic fracturing to earthquakes. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms. Any additional level of regulation could lead to operational delays or increased operating costs which could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and would increase our costs of doing business, and could adversely affect our financial condition and results of operations.

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operations sectors, including to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information, and to communicate with our employees and third-party partners. Any future cyber security attacks that affect our facilities, our customers and any financial data could lead to data corruption, communication interruption, or other disruptions in our development operations or planned business transactions, any of which could have a material adverse effect on our business. In addition, security cyber attacks on our customer and employee data may result in a financial loss and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results. Further, as cyber security 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 vulnerabilities to cyber security attacks.

Risks Inherent in an Investment in Us

Our general partner controls us, and the Founders, our Mid-Con Affiliate and Yorktown own an approximate 20% interest in us. They have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.

Our general partner has control over all decisions related to our operations. Our general partner is controlled by Messrs. Charles R. Olmstead and Jeffrey R. Olmstead. As of December 31, 2017, the Founders, our Mid-Con Affiliate and Yorktown own an approximate 20% interest in us. Although our general partner has a duty to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a duty to manage our general partner in a manner beneficial to its owners. All of the executive officers and non-independent directors of our general partner are also officers and/or directors of the Mid-Con Affiliate and will continue to have economic interests in, as well as management and fiduciary duties to, the Mid-Con Affiliate. Additionally, one of the directors of our general partner is a principal with Yorktown. As a result of these relationships, conflicts of interest may arise in the future between the Mid-Con Affiliate and Yorktown and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our limited partner unitholders. These potential conflicts include, among others:

 

our Partnership Agreement limits our general partner’s liability, replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and also restricts the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing common

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units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

 

neither our Partnership Agreement nor any other agreement requires the Mid-Con Affiliate and Yorktown or their respective affiliates (other than our general partner) to pursue a business strategy that favors us. The officers and directors of the Mid-Con Affiliate and Yorktown and their respective affiliates (other than our general partner) have a duty to make these decisions in the best interests of their respective equity holders, which may be contrary to our interests;

 

the Mid-Con Affiliate and Yorktown and their affiliates are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer or sell assets to us;

 

all of the executive officers of our general partner who provide services to us also devote a significant amount of time to the Mid-Con Affiliate and are compensated for those services rendered;

 

our general partner determines the amount and timing of our development operations and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other businesses with which our general partner is or may become affiliated, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;

 

we entered into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating provides management, administrative and operational services to us, and Mid-Con Energy Operating will also provide these services to the Mid-Con Affiliate;

 

our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

 

our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

 

our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

 

our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

 

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.

Neither we nor our general partner have any employees, and we rely solely on Mid-Con Energy Operating to manage and operate our business. The management team of Mid-Con Energy Operating, which includes the individuals who manage us, also provides substantially similar services to the Mid-Con Affiliate, and thus is not solely focused on our business.

Neither we nor our general partner have any employees, and we rely solely on Mid-Con Energy Operating to provide management, administrative and operational services to us. Mid-Con Energy Operating provides substantially similar services and personnel to the Mid-Con Affiliate and, as a result, may not have sufficient human, technical and other resources to provide those services at a level that it would be able to provide to us if it did not provide similar services to these other entities. Additionally, Mid-Con Energy Operating may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of the Mid-Con Affiliate or other affiliates of our general partner. There is no requirement that Mid-Con Energy Operating favor us over these other entities in providing its services. If the employees of Mid-Con Energy Operating do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

Increases in interest rates could adversely affect our business, results of operations, cash flows from operations and financial condition, and cause a decline in the demand for yield-based equity investments such as our common units and the Preferred Units.

All of the indebtedness outstanding under our revolving credit facility is at variable interest rates; therefore, we have significant exposure to increases in interest rates. As a result, our business, results of operations and cash flows may be adversely affected by significant increases in interest rates. Further, an increase in interest rates may cause a corresponding decline in demand for equity investments, in particular for equity investments such as our common units. Any reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.

Our Preferred Units rank senior in right of payment to our common units, and we are unable to make any distributions to our common unitholders unless full cumulative distributions are made on our Preferred Units.

Our Class A Preferred Units and Class B Preferred Units rank senior to the common units with respect to distribution rights and rights upon liquidation. Subject to certain exceptions, as long as any Preferred Units remain outstanding, we may not declare any distribution on our common units unless all accumulated and unpaid distributions have been declared and paid on the Preferred Units. In

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the event of our liquidation, winding-up or dissolution, the holders of the Preferred Units would have the right to receive proceeds from any such transaction before the holders of the common units. The payment of the liquidation preference could result in common unitholders not receiving any consideration if we were to liquidate, dissolve or wind-up, either voluntarily or involuntarily. Additionally, the existence of the liquidation preference may reduce the value of the common units, make it harder for us to issue and sell common units in the future, or prevent or delay a change in control.

Our obligation to pay distributions on, and other restrictions associated with, the Preferred Units could impact our liquidity and our ability to finance future operations.

Our obligation to pay distributions on the Preferred Units could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and other general partnership purposes. Also, as long as any Preferred Units are outstanding, subject to certain exceptions, the affirmative vote or consent of the holders of at least a majority of the outstanding Preferred Units, voting together as a separate class, will be necessary for effecting or validating, among other things: (i) any action to be taken that adversely affects any of the rights, preferences or privileges of the Preferred Units, (ii) amending the terms of the Preferred Units, (iii) the issuance of any additional Preferred Units or equity security senior or pari passu in right of distribution or in liquidation to the Preferred Units, (iv) the ability to incur indebtedness (other than under our existing credit facility or trade payables arising in the ordinary course of business) or (v) lift the suspension of the at-the-market offering program. These restrictions may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

The holders of our Preferred Units are entitled to convert their Preferred Units or cause us to redeem them, which could dilute the holders of our common units and require us to raise cash to fund a redemption.

The holders of our Preferred Units may convert the Preferred Units into common units on a one-for-one basis at any time after the six-month anniversary of the applicable closing date, in whole or in part, subject to certain conversion thresholds. At any time after the fifth anniversary of the Class A Preferred Unit closing date, each holder of the Preferred Units shall have the right to cause us to redeem all or any portion of the outstanding Preferred Units for cash. In addition, in connection with a change of control of the Partnership, holders of Preferred Units may elect to have their Preferred Units converted into common units, plus accrued but unpaid distributions to the conversion date, and if holders of Preferred Units do not elect to convert all of their Preferred Units, then, unless the Partnership is the surviving entity of the change of control, we must redeem any remaining Preferred Units in cash.

If a substantial portion of the Preferred Units are converted into common units, common unitholders could experience significant dilution. Further, if holders of converted Preferred Units dispose of a substantial portion of such common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price for our common units. These sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future. In addition, if we are required to redeem outstanding Preferred Units, it would result in a significant cash expenditure and, if we did not have sufficient funds on hand at that time, we would have to incur borrowings or otherwise finance the cost of such redemption.

Units held by persons who our general partner determines are not eligible holders will be subject to redemption.

To comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our common units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means:

 

a citizen of the United States;

 

a corporation organized under the laws of the United States or of any state thereof;

 

a public body, including a municipality;

 

an association of U.S. citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof; or

 

a limited partner whose nationality, citizenship or other related status would not, in the determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we or our subsidiary has an interest.

Onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under U.S. laws or of any state thereof. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder run the risk of having their common units redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

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Our unitholders have limited voting rights and are not entitled to elect our general partner or its Board of Directors, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders have no right on an annual or ongoing basis to elect our general partner or its Board of Directors. The Board of Directors of our general partner, including the independent directors, is chosen entirely by Charles R. Olmstead and Jeffrey R. Olmstead, the voting members of our general partner, and not by our unitholders. Unlike publicly traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if our unitholders are dissatisfied, it would be difficult to remove our general partner without its consent.

The vote of the holders of at least 66.67% of all outstanding units is required to remove our general partner. As of December 31, 2017, the Founders, our Mid-Con Affiliate and Yorktown own an approximate 20% interest in us, which will enable those holders, collectively, to make it difficult to remove our general partner.

Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our Partnership Agreement does not restrict the ability of the Founders from transferring all or a portion of their ownership interests in our general partner to a third party. The new owner of our general partner would then be in a position to replace the Board of Directors and officers of our general partner with their own choices and thereby influence the decisions made by the Board of Directors and officers in a manner that may not be aligned with the interests of our unitholders.

We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests.

Our Partnership Agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting, including additional Preferred Units. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

 

our unitholders’ proportionate ownership interest in us will decrease;

 

the amount of cash available for distribution on each unit may decrease;

 

the ratio of taxable income to distributions may increase;

 

the relative voting strength of each previously outstanding unit may be diminished; and

 

the market price of our common units may decline.

Our Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units, other than our general partner and its affiliates, the holders of our Preferred Units and Yorktown, which may limit the ability of significant common unitholders to influence the manner or direction of management.

Our Partnership Agreement restricts unitholders’ voting rights by providing that any common units held by a person, entity or group owning 20% or more of any class of common units then outstanding, other than our general partner and its affiliates, the holders of our Preferred Units, Yorktown and their transferees and persons who acquired such common units with the prior approval of the Board of Directors of our general partner, cannot vote on any matter. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

Sales of our common units by the selling unitholders may cause our price to decline.

As of December 31, 2017, the Founders, our Mid-Con Affiliate and Yorktown own 5,472,162 common units and 360,000 units held by our general partner, or an approximate 20% interest in us. Sales of these units or of other substantial amounts of our common units in the public market, or the perception that these sales may occur, could cause the market price of our common units to decline. Sales of such units could also impair our ability to raise capital through the sale of additional common units.

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Our unitholders liability may not be limited if a court finds that 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 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 do business. A unitholder could be liable for our obligations as if it was 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

 

a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business.

Our unitholders may have liability to repay distributions.

Although we have suspended distributions on our common units, under certain circumstances, 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 distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an 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. This requirement could apply to quarterly distributions made before suspension and to future distributions, in the event we elect to reinstate the distributions. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our Partnership Agreement.

Tax Risks to Unitholders

Our unitholders are required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.

In October 2015, our Board elected to suspend quarterly cash distributions on our common units. Because our unitholders are treated as partners to whom we will allocate taxable income, which could be different in amount than the cash we distribute, our unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. Additionally, we may engage in transactions to delever the Partnership and manage our liquidity that may result in income and gain to our unitholders without a corresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, unitholders may be allocated taxable income or gain resulting from the sale without receiving a cash distribution.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement, or a change in current law, could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and would likely pay state and local income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions which would be taxable as dividends for U.S. federal income tax purposes to the extent paid out of our current or accumulated earnings and profits as determined for U.S. federal income tax purposes, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders 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 our unitholders, likely causing a substantial reduction in the value of our units.

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If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our units.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time the U.S. President and members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that would affect publicly traded partnerships or an investment in our units. Additionally, final Treasury Regulations under Section 7704(d)(1)(E) of the Internal Revenue Code of 1986, as amended (the “Code”), interpret the scope of qualifying income for publicly traded partnerships by providing industry-specific guidance. We believe the income that we treat as qualifying income satisfies the requirements for qualifying income under the current law and the final Treasury Regulations.

In addition, the Tax Cuts and Jobs Act (the “TCJA”) enacted December 22, 2017, makes significant changes to the federal income tax rules applicable to both individuals and entities, including changes to the tax rate on an individual or other non-corporate unitholder’s allocable share of certain income from a publicly traded partnership. The TCJA is complex and lacks administrative guidance, thus, the impact of certain aspects of its provisions on us or an investment in our units is currently unclear. Unitholders should consult their tax advisor regarding the TCJA and its effect on an investment in our units.

Any changes to the U.S. federal income tax laws and interpretations thereof (including administrative guidance relating to the TCJA) may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception to be treated as a partnership for U.S. federal income tax purposes or otherwise adversely affect us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes or interpretations thereof could negatively impact the value of an investment in our units.

If the IRS contests any of the federal income tax positions we take, the market for our units may be adversely affected, and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may not agree with those positions. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

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

If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their adjusted tax basis in their units. Because prior distributions in excess of their allocable share of our total net taxable income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion, amortization and Intangible Drilling Costs deduction recapture. In addition, because the amount realized may include a unitholder’s share of our non-recourse liabilities, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Unitholders may be subject to limitations on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the TCJA, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income plus 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, depletion or amortization. Any interest disallowed may be carried forward and deducted in future years by the unitholder from his share of our “excess taxable income,” which is generally equal to the excess of 30% of our adjusted taxable income over the amount of our deduction for business interest for such future taxable year, subject to certain restrictions.  

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

Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts, (“IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units.

We will treat each purchaser of units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.

Because we cannot match transferors and transferees of units and because of other reasons, we will adopt depreciation, depletion and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of units and could have a negative impact on the value of our units or result in audits of and adjustments to a unitholder’s tax return.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Although final Treasury Regulations allow publicly traded partnerships to use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, these regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge our proration method or new Treasury Regulations were issued, we may be required to change our method of allocating items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are the subject of a securities loan (e.g. a loan to a “short seller” to affect a short sale of units) may be considered as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any items of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units.

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates ourselves using a methodology based on the market value of our units as a means to determine the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of units and could have a negative impact on the value of the units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

31


As a result of investing in our units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future even if such unitholders do not live in those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We own property and conduct business in many states, some of which impose a personal income tax on individuals and impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. We may own property or conduct business in other states or foreign countries in the future. It is a unitholder’s responsibility to file all U.S. federal, state and local tax returns.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

Oil and Natural Gas Reserves

Internal Controls Relating to Reserve Estimates

We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our internal controls over the recording of reserves estimates require reserve estimates to be in compliance with the SEC rules, regulations, definitions and guidance. Our proved reserves are estimated at the well, lease, or unit level and compiled for reporting purposes by our reservoir engineering staff. Internal evaluations of our reserves are maintained in a secure reserve engineering database. Reserves are reviewed internally by our senior management on a quarterly basis. Our reserve estimates are audited by our independent third-party reserve engineers, CG&A, at least annually.

Our staff works closely with CG&A to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve audit process. To facilitate their audit of our reserves, we provide CG&A with any information they may request, including all of our reserve information as well as geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures, LOE, product pricing, production taxes and relevant economic criteria. We also make all of our pertinent personnel available to CG&A to respond to any questions they may have.

Technology Used to Establish Proved Reserves

Under the SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our internal reserve engineers and CG&A employ technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, injection data, seismic data and well test data. Reserves attributable to producing properties with sufficient production history are estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing properties with limited production history and for undeveloped locations are estimated using performance from analogous properties in the surrounding area and geologic data to assess the reservoir continuity. These properties were considered to be analogous based on production performance from the same formation and similar completion techniques.

Qualifications of Responsible Technical Persons

CG&A is an independent oil and natural gas consulting firm. No director, officer, or key employee of CG&A has any financial ownership in the Partnership, the Mid-Con Affiliate, Mid-Con Energy Operating or any of their respective affiliates. The compensation paid to CG&A for the audit is not contingent upon the results obtained and reported. The engineering audit presented in the CG&A

32


report was overseen by W. Todd Brooker, President. Mr. Brooker has been a Petroleum Consultant for CG&A since 1992, became Senior Vice President in 2011 and President in 2017. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition and divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. Prior to CG&A he worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. He is a registered professional engineer in Texas, No. 83462, and a member of the Society of Petroleum Engineers.

Chad B. Roller, Ph.D., Vice President of Development of Mid-Con Energy Operating, has served in this role since March 2015. Dr. Roller previously served as Petroleum Engineer at Mid-Con Energy Operating and Royal Dutch Shell where his expertise includes waterflood development and EOR. Dr. Roller received his Ph.D. from Rice University and Master of Science and Bachelor of Science degrees from the University of Oklahoma.

Estimated Proved Reserves

The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2017, based on reserve reports prepared by our reservoir engineering staff and audited by CG&A.

 

 

 

Net Oil

MBbls

 

 

Net Gas

MMcf

 

 

Total

Net MBoe

 

Reserve Data(1)

 

 

 

 

 

 

 

 

 

 

 

 

Estimated proved developed reserves

 

 

13,512

 

 

 

4,586

 

 

 

14,276

 

Estimated proved undeveloped reserves

 

 

4,998

 

 

 

1,696

 

 

 

5,281

 

Total

 

 

18,510

 

 

 

6,282

 

 

 

19,557

 

 

(1)

Our estimated net proved reserves were determined using index prices for oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $51.34 per Bbl for oil and $2.98 per MMBtu for natural gas at December 31, 2017. These prices were adjusted by lease for quality, transportation fees, location differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Average adjusted prices used were $49.34 per Bbl of oil and $2.27 per Mcf of natural gas.

The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, see Item 1A. “Risk Factors - Risks Related to Our Business.” Our estimated proved reserves and future production rates rely on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure amounts should not be construed as the current market value of our estimated oil reserves. The 10% discount factor used to calculate standardized measure, which is required by Financial Accounting Standard Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Development of Proved Undeveloped Reserves

With respect to PUDs, we have established a development plan approved by the Vice President of Development of Mid-Con Energy Operating that will result in converting the PUDs within five years from the initial disclosure of the reserves and the associated development capital requirements are equal to or less than the management-approved capital program on a year-by-year basis. If either of these criteria cease to be met, we remove the associated PUDs from our proved reserves disclosures. None of our proved undeveloped reserves as of December 31, 2017, have remained undeveloped for more than five years from the date the reserves were initially booked as proved undeveloped.

Our development plan includes PUDs that are based upon qualitative and quantitative factors including estimated risk-based returns, current pricing forecasts, recent drilling results and waterflood responses. None of our PUDs at December 31, 2017, are scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. Consistent with the typical waterflood response time range of 6-18 months from initial development, the transfer of PUDs to the proved developed category is attributable to development costs incurred. During 2017, our capital expenditures for development (drilling, recompletion and conversion to injection) were $7.4 million. Based on our current expectations of cash flows, we expect to fund our 2018 capital spending program from our cash flows from operations. For a more detailed discussion of our pro forma liquidity position,

33


see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.”

The following table summarizes the changes in our PUDs during the year ended December 31, 2017:

 

 

 

Net Oil

 

 

Net Gas

 

 

Total

 

 

 

MBbls

 

 

MMcf

 

 

Net MBoe

 

Proved undeveloped reserves as of December 31, 2016

 

 

6,477

 

 

 

1,983

 

 

 

6,808

 

Conversion to proved developed reserves

 

 

(1,825

)

 

 

(380

)

 

 

(1,888

)

Revisions of previous estimates(1)

 

 

680

 

 

 

93

 

 

 

695

 

Purchases of proved undeveloped reserves

 

 

343

 

 

 

 

 

 

343

 

Extensions and discoveries of proved undeveloped reserves

 

 

24

 

 

 

 

 

 

 

24

 

Sales of proved undeveloped reserves

 

 

(701

)

 

 

 

 

 

(701

)

Reduction due to aged five or more years

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves as of December 31, 2017

 

 

4,998

 

 

 

1,696

 

 

 

5,281

 

(1) Revisions of previous estimates represent changes in the previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

For the year ended December 31, 2017, our PUDs decreased from 6,808 MBoe to 5,281 MBoe. The change was primarily attributable to:

Conversion to proved developed reserves. We converted 1,888 MBoe from PUDs to proved developed reserves.

Revisions of previous estimates. Commodity prices improved in 2017. The 12-month average price for crude oil increased 20% from $42.75 per Bbl for 2016 compared to $51.34 per Bbl for 2017, while the 12-month average price for natural gas increased 20% from $2.49 per MMBtu for 2016 compared to $2.98 per MMBtu for 2017. The increase in benchmark prices had a modest positive impact on our PUDs estimates, resulting in upward reserve revisions of 60 MBoe during the year ending December 31, 2017. We saw continued positive oil production responses to water injection in our Texas core area from both existing and new waterflood projects that resulted in an upward revision of 635 MBoe in PUDs.  

Purchases of proved undeveloped reserves. The Oklahoma Wheatland property acquisition, which closed June 1, 2017, resulted in a positive increase of 343 MBoe in PUDs.

Extensions and discoveries of proved undeveloped reserves. These were additions to PUDs that resulted from successful offset drilling in our Texas core area during the year ended December 31, 2017.

Sales of proved undeveloped reserves. Reductions to PUDs from the divestiture of Southern Oklahoma properties on December 22, 2017, and resulted in a decrease in PUDs of 701 MBoe.

Developed and Undeveloped Acreage

The following table sets forth information relating to our leasehold acreage. Acreage related to royalty, overriding royalty and other similar interests were excluded from this table. As of December 31, 2017, 96% of our leasehold acreage was held by production:

 

 

 

Developed Acreage

 

 

Undeveloped Acreage

 

Core Area

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Oklahoma

 

 

14,689

 

 

 

11,720

 

 

 

 

 

 

 

Texas

 

 

18,630

 

 

 

17,510

 

 

 

1,290

 

 

 

1,240

 

Total

 

 

33,319

 

 

 

29,230

 

 

 

1,290

 

 

 

1,240

 

All of the PUDs in the Oklahoma core area are related to new drilling or recompletion activities within currently producing areas of our developed acreage and represent in-fill or reduced spacing activity; therefore, all acreage is considered developed.

34


Drilling Activities

For information with respect to wells drilled and completed for the years ended December 31, 2017, and 2016, see Item 1. “Business - Drilling Activities”.

Productive Wells

For information with respect to the number of productive oil and natural gas wells on our properties for the years ended December 31, 2017, and 2016, see Item 1. “Business - Productive Wells”.

Title to Properties

Prior to completing an acquisition of producing oil properties, we perform title reviews on significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.

We initially conduct only a review of the titles to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

We believe that we have satisfactory title to all of our material properties. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business.

ITEM 3.

LEGAL PROCEEDINGS

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. No amounts have been accrued at December 31, 2017.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

35


PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are listed under the symbol “MCEP” on the NASDAQ. At the close of business on February 19, 2018, based upon information received from our transfer agent and brokers and nominees, we had 37 limited partner unitholders of record. This number does not include owners for whom common units may be held in “street” names. The daily high and low closing prices per common unit for the period from January 1, 2017, through December 31, 2017, were $3.22 and $0.93, respectively.

The following table sets forth the range of the daily high and low prices per common unit for 2016 and 2017:  

 

 

 

Price Range

 

 

 

High

 

 

Low

 

2016

 

 

 

 

 

 

 

 

First Quarter

 

$

1.93

 

 

$

0.72

 

Second Quarter

 

$

4.05

 

 

$

1.70

 

Third Quarter

 

$

3.08

 

 

$

1.40

 

Fourth Quarter

 

$

3.30

 

 

$

1.93

 

 

 

 

 

 

 

 

 

 

2017

 

 

 

 

 

 

 

 

First Quarter

 

$

3.37

 

 

$

0.72

 

Second Quarter

 

$

2.53

 

 

$

1.70

 

Third Quarter

 

$

1.43

 

 

$

1.40

 

Fourth Quarter

 

$

1.45

 

 

$

1.93

 

Cash Distributions to Unitholders

In October 2015, prolonged declines in commodity prices prompted us to suspend cash distributions to common unitholders in an effort to preserve liquidity and reallocate excess cash flow towards capital expenditure projects and debt reduction to maximize long-term value for our unitholders. There is no assurance as to future cash distributions since they are dependent upon our projections for future earnings, cash flows, capital requirements, financial conditions and other factors. Our credit agreement stipulates written consent from our lenders is required in order to reinstate common unit distributions. Management and the Board will continue to evaluate, on a quarterly basis, the appropriate level of cash reserves in determining any future distributions.

Cash Distribution Policy

Our Partnership Agreement requires us to distribute all of our available cash on a quarterly basis to unitholders of record on the applicable record date. Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

 

less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:

 

provide for the proper conduct of our business (including reserves for future capital expenditures, working capital and operating expenses) subsequent to that quarter;

 

comply with applicable laws, any of our loan agreements, security agreements, mortgage debt instruments or other agreements; or

 

provide funds for cash distributions to our preferred and common unitholders (including our general partner) for any one or more of the next four quarters;

 

plus, if our general partner so determines, all or a portion of cash or cash equivalents on hand on the date of determination of available cash for the quarter.

See Note 10 to the Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for additional information.

Securities Authorized for Issuance under Equity Compensation Plans

See Item 11. “Executive Compensation - Long-Term Incentive Program” for information regarding our equity compensation plans as of December 31, 2017.

36


Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

ITEM 6.

SELECTED FINANCIAL DATA

As a smaller reporting company, we are not required to provide the information otherwise required by this item.

 

 

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with Item 8. “Financial Statements and Supplementary Data” contained herein.

Overview

Mid-Con Energy Partners is a publicly held limited partnership formed in July 2011 that engages in the ownership, acquisition and development of producing oil and natural gas properties in North America, with a focus on EOR. Our properties are located primarily in the Mid-Continent and Permian Basin regions of the United States in our Oklahoma and Texas core areas. In 2017, we sold all of our Southern Oklahoma properties. Our properties primarily consist of mature, legacy onshore oil reservoirs with long-lived, relatively predictable production profiles and low production decline rates.  

As of December 31, 2017, our total estimated proved reserves were 19.6 MMBoe, of which 95% were oil and 73% were proved developed, both on a Boe basis. As of December 31, 2017, we operated 100% of our properties through our affiliate, Mid-Con Energy Operating, and 64% of our net proved reserves were being produced under waterflood, in each instance on a Boe basis. Our average net production for the month ended December 31, 2017, was 3,163 Boe/d and our total estimated proved reserves had a reserve-to-production ratio of 17 years.

Recent Developments

Wheatland Acquisition

On June 1, 2017, we acquired multiple oil and natural gas properties located in Oklahoma County and Cleveland County, Oklahoma for cash consideration of $4.1 million, after preliminary post-closing purchase price adjustments. The effective date of the acquisition was April 1, 2017. See Note 3 to the Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for additional information.

Southern Oklahoma Divestiture

On December 22, 2017, we completed the sale of properties in the Southern Oklahoma region (the “Southern Oklahoma divestiture”) for cash proceeds of $22.0 million, prior to post-closing purchase price adjustments, and recognized a loss of $4.2 million. The effective date of the divestiture was December 22, 2017. See Note 3 to the Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for additional information.

Nolan County Divestiture

On January 9, 2018, we completed the sale of certain Permian oil and natural gas proved properties in Nolan County, Texas (the “Nolan County divestiture”), for cash consideration of $1.6 million, subject to customary post-closing sale price adjustments. The effective date of the divestiture was November 1, 2017.

House Creek Acquisition

On January 16, 2018, we acquired multiple oil and natural gas properties located in Campbell County, Wyoming (“House Creek”), for cash consideration of $1.5 million, subject to customary post-closing sale price adjustments. The effective date of the acquisition was September 1, 2017.

37


Class B Preferred Unit Offering

On January 31, 2018, we closed the private placement of 9,803,921 Class B Preferred Units for an aggregate offering price of $15.0 million. The Partnership used a portion of the proceeds from the offering to fund the acquisition of certain properties in Campbell and Converse Counties, Wyoming, and any excess was used to reduce borrowings under our revolving credit facility. The Class B Preferred Units were issued at a price of $1.53 per Preferred Unit (the “Class B Unit Purchase Price”). The Partnership will pay holders of the Class B Preferred Units a cumulative, quarterly distribution in cash at an annual rate of 8.0%, or under certain circumstances, in additional Class B Preferred Units, at an annual rate of 10.0%. At any time after the six month anniversary and prior to August 11, 2021, each holder of the Class B Preferred Units may elect to convert all or any portion of their units into common units representing limited partner interests in the Partnership on a one-for-one basis. On August 11, 2021, each holder may elect to cause the Partnership to redeem all or any portion of their Class B Preferred Units for cash at the Class B Unit Purchase Price, and any remaining Class B Preferred Units will thereafter be converted to common units on a one-for-one basis.

Pine Tree Acquisition

On January 31, 2018, we acquired multiple oil and natural gas properties located in Campbell and Converse Counties, Wyoming (“Pine Tree”), for cash consideration of $8.6 million, subject to customary post-closing sale price adjustments. The effective date of the acquisition was September 1, 2017. The purchase price was funded by the Class B Preferred Unit offering described above.

Revolving Credit Facility

During the quarter ended September 30, 2017, we were not in compliance with our leverage ratio calculation. On November 10, 2017, the Partnership received a waiver from the Administrative Agent and the Lenders of our revolving credit facility waiving the noncompliance through December 15, 2017. On December 22, 2017, Amendment 11 to the credit agreement was finalized. The amendment extended the waiver of the leverage ratio default until January 31, 2018. This amendment decreased the Partnership’s borrowing base to $115.0 million effective December 22, 2017, and required the facility usage not exceed $100.0 million. The amendment also required that the cash proceeds received from the Southern Oklahoma divestiture on December 22, 2017, and the Nolan County divestiture on January 9, 2018, be applied to the borrowings outstanding.

On January 31, 2018, we finalized Amendment 12 to our revolving credit facility, which increased our borrowing base to $125.0 million and extended the maturity of the facility from November 2018 to November 2020. The lenders also waived any default or event of default that occurred as a result of the Partnership’s failure to maintain the required leverage ratio for the quarter ended September 30, 2017. The amendment also required the Partnership to have a minimum liquidity of 20% prior to making any distributions to the Preferred Unitholders.

Reduction of Debt

As of February 28, 2018, we had reduced outstanding debt by $31.8 million since December 31, 2016. Funds for debt repayment were provided by the Southern Oklahoma and Nolan County divestitures, remaining proceeds from the Class B Preferred Unit offering in excess of the Pine Tree acquisition and cash flows from operations.

Distributions

In 2017, we paid cash distributions on Class A Preferred Units of $1.5 million for fourth quarter 2016 and first and second quarter 2017. On January 31, 2018, the Partnership announced that the Board declared a Class A Preferred Unit cash distribution for the third and fourth quarters of 2017, according to terms outlined in the Partnership Agreement. A cash distribution of $0.086 per Class A Preferred Unit, or $1.0 million in aggregate, was paid on February 14, 2018, to holders of record as of the close of business on February 7, 2018.

As of February 28, 2018, cash distributions on our common units continued to be indefinitely suspended. Our credit agreement stipulates written consent from our lenders is required in order to reinstate common unit distributions and also prohibits us from making common unit cash distributions if any potential default or event of default, as defined in the credit agreement, occurs or would result from the cash distribution. Management and the Board will continue to evaluate, on a quarterly basis, the appropriate level of cash reserves in determining future distributions. The suspension of common unit cash distributions is designed to preserve liquidity and reallocate excess cash flow towards capital expenditure projects and debt reduction to maximize long-term value for our unitholders.

Appointment and Departure of Certain Officers

Mr. S. Craig George resigned from the Board effective January 31, 2017.

Mr. Wilkie S. Colyer Jr. was appointed to the Board effective February 1, 2017.

Mr. John W. Brown was appointed to the Board and the audit committee effective April 25, 2017.

38


Mr. Matthew R. Lewis resigned from his position of Vice President and Chief Financial Officer of the general partner effective November 6, 2017, and served in an advisory role until November 30, 2017.

Business Environment

The markets for oil, natural gas and NGLs have been volatile and may continue to be volatile in the future, which means that the price of oil and natural gas may fluctuate widely. Sustained periods of low prices for oil and natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. Our average sales price per barrel of oil, excluding commodity derivative contracts, was $47.72 and $39.52 for the years ended December 31, 2017, and 2016, respectively.

The following table is a summary of NYMEX-WTI futures prices for the years ended December 31, 2017, and 2016:

 

 

 

Price Range

 

 

 

 

 

 

 

High

 

 

Low

 

 

Average

 

2017

 

$

60.42

 

 

$

42.53

 

 

$

50.85

 

2016

 

$

54.06

 

 

$

26.21

 

 

$

43.47

 

Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivative contracts (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices. The commodity derivative contracts that we have entered into generally have the effect of providing us with a fixed price or a floor for a portion of our expected future oil production over a fixed period of time. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent to do so, or as required by our lenders. We conduct our risk management activities exclusively with participant lenders in our revolving credit facility. We have entered oil commodity derivative contracts covering a portion of our anticipated oil production through September 2020 as of February 28, 2018.

Our business faces the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well or formation decreases. Although our waterflood operations tend to restore reservoir pressure and production, once a waterflood is fully effected, production, once again, begins to decline. Our future growth will depend on our ability to continue to add reserves in excess of our production. Our focus on adding reserves is primarily through improving the economics of producing oil from our existing fields and, secondarily, through acquisitions of additional proved reserves. Our ability to add reserves through development projects and acquisitions is dependent upon many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and close acquisitions.

We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flows from operations are impacted by our ability to manage our overall cost structure.

How We Evaluate Our Operations

Our primary business objective is to manage our oil and natural gas properties for the purpose of generating stable cash flows, which will provide stability and, over time, growth of distributions to our unitholders. The amount of cash that we can distribute to our unitholders depends principally on the cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other factors:

 

the amount of oil and natural gas we produce;

 

the prices at which we sell our oil and natural gas production;

 

our ability to hedge commodity prices; and

 

the level of our operating and administrative costs.

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas properties, including:

 

oil and natural gas production volumes;

 

realized prices on the sale of oil and natural gas, including the effect of our commodity derivative contracts;

 

LOE; and

 

adjusted EBITDA.

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to assess the cash flow generated by our assets, without regard to financing methods, capital structure or historical cost basis and our ability to incur and service debt and fund capital expenditures. In addition, management uses Adjusted EBITDA to evaluate actual potential cash flow available to reduce debt, develop existing reserves or acquire additional properties and pay distributions to our unitholders. Adjusted EBITDA is a non-U.S. GAAP

39


measure and should not be considered an alternative to net income (loss), net cash provided by operating activities or any other performance or liquidity measure determined in accordance with U.S. GAAP. In addition, our calculations of Adjusted EBITDA are not necessarily comparable to EBITDA or Adjusted EBITDA as calculated by other companies.

Results of Operations

The tables presented in this section summarize certain of the results of operations and period-to-period comparisons for the years ended December 31, 2017, and 2016. Because of normal production declines, changes in drilling activities, fluctuations in commodity prices and the effects of acquisitions and divestitures, the historical data presented below should not be interpreted as being indicative of future results.

Production and Unit Costs per BOE. The following table provides production volume data and average unit costs per BOE:

 

 

 

Year Ended December 31,

 

 

 

 

 

 

 

 

 

 

 

2017

 

 

2016

 

 

Change

 

 

% Change

 

Production Volumes

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

1,209

 

 

 

1,386

 

 

 

(177

)

 

 

(13

%)

Natural gas (MMcf)

 

 

431

 

 

 

554

 

 

 

(123

)

 

 

(22

%)

Total (MBoe)

 

 

1,281

 

 

 

1,478

 

 

 

(197

)

 

 

(13

%)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily net production (Boe/d)

 

 

3,510

 

 

 

4,038

 

 

 

(528

)

 

 

(13

%)